System and method for high efficiency power generation using a carbon dioxide circulating working fluid

ABSTRACT

The present invention provides methods and system for power generation using a high efficiency combustor in combination with a CO 2  circulating fluid. The methods and systems advantageously can make use of a low pressure ratio power turbine and an economizer heat exchanger in specific embodiments. Additional low grade heat from an external source can be used to provide part of an amount of heat needed for heating the recycle CO 2  circulating fluid. Fuel derived CO 2  can be captured and delivered at pipeline pressure. Other impurities can be captured.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present patent application claims priority to U.S. ProvisionalPatent Application No. 61/299,272, filed Jan. 28, 2010, and U.S. patentapplication Ser. No. 12/714,074, filed Feb. 26, 2010, which claimspriority to U.S. Provisional Patent Application No. 61/155,755, filedFeb. 26, 2009, the disclosures of which are incorporated herein byreference in their entirety.

FIELD OF THE INVENTION

The present invention is directed to systems and methods for generationof power, such as electricity, through use of a circulating fluid totransfer energy generated through high efficiency combustion of a fuel.Particularly, the system and method can use carbon dioxide as thecirculating fluid.

BACKGROUND OF THE INVENTION

It is estimated that fossil fuels will continue to provide the bulk ofthe world's electric power requirements for the next 100 years whilenon-carbon power sources are developed and deployed. Known methods ofpower generation through combustion of fossil fuels and/or suitablebiomass, however, are plagued by rising energy costs and an increasingproduction of carbon dioxide (CO₂) and other emissions. Global warmingis increasingly seen as a potentially catastrophic consequence ofincreased carbon emissions by the developed and developing nations.Solar and wind power do not appear capable of replacing fossil fuelcombustion in the near term, and nuclear power has dangers associatedwith both proliferation and nuclear waste disposal.

Conventional means of power production from fossil fuels or suitablebiomass now are increasingly being burdened with a requirement for CO₂capture at high pressure for delivery to sequestration sites. Thisrequirement is proving difficult to fulfill, however, since presenttechnology only provides for very low thermal efficiencies for even thebest designs for CO₂ capture. Moreover, capital costs for achieving CO₂capture are high, and this results in significantly higher electricitycosts compared to systems that emit CO₂ into the atmosphere.Accordingly, there is an ever growing need in the art for systems andmethods for high efficiency power generation allowing for a reduction inCO₂ emission and/or improved ease of sequestration of produced CO₂.

SUMMARY OF THE INVENTION

The present invention provides methods and system for power generationusing a high efficiency combustor (e.g., a transpiration cooledcombustor) in combination with a circulating fluid (e.g., a CO₂circulating fluid). In particular, the circulating fluid can beintroduced into the combustor along with a fuel and an oxidant forcombustion such that a high pressure, high temperature fluid stream isproduced comprising the circulating fluid and any combustion products.The fluid stream can be introduced into a power generation device, suchas a turbine. Advantageously, the fluid stream can be maintained at arelatively high pressure during expansion in the turbine such that thepressure ratio across the turbine (i.e., the ratio of the pressure atthe turbine inlet and the pressure at the turbine outlet) is less thanabout 12. The fluid stream can then be further processed for separationof the components of the fluid stream, which can include passing thefluid stream through a heat exchanger. In particular, the circulatingfluid (at least a portion of which may be recycled from the fluidstream) can be passed through the same heat exchanger to heat thecirculating fluid prior to introduction into the combustor. In suchembodiments, it may be useful to operate the heat exchanger (e.g.,through selection of a low grade heat source) such that heat exchangerhas only a small temperature difference between the turbine exhaust andthe recycle fluid at the hot end of the heat exchanger.

In certain aspects, the invention provides power production systems thatcan produce power at high efficiency with low capital cost and also canproduce substantially pure CO₂ at pipeline pressure for sequestration.The CO₂ also may be recycled into the power production system.

The inventive systems and methods are characterized by the ability touse a wide variety of fuel sources. For example, the high efficiencycombustor used according to the invention can make use of gaseous (e.g.,natural gas or coal derived gases), liquid (e.g., hydrocarbons, bitumen)and solid (e.g., coal, lignite, pet-coke) fuels. Even further fuels, asotherwise described herein, could be used.

In other aspects, the methods and systems of the invention areparticularly useful in that they can exceed the best efficiency ofcurrent coal fired power stations that do not provide for the capture ofCO₂. Such current power stations can provide, at best, about 45%efficiency (lower heating value, or “LHV”) with 1.7 inches mercurycondenser pressure using a bituminous coal. The present system canexceed such efficiency while also delivering CO₂ for sequestration orother disposal at required pressures.

In still another aspect, the present invention provides the ability toreduce the physical size and capital cost of a power generation systemcompared to current technologies using a similar fuel. Thus, the methodsand systems of the present invention can significantly reduceconstruction costs associated with power production systems.

Still further, the methods and systems of the present invention canprovide for the recovery of virtually 100% of the CO₂ used and/orproduced, especially CO₂ derived from carbon present in the fuel.Particularly, the CO₂ can be provided as a dried, purified gas atpipeline pressure. Moreover, the invention provides the ability toseparately recover other fuel and combustion derived impurities forother use and/or disposal.

In one particular aspect, the present invention is directed to a methodof power generation incorporating the use of a circulating fluid, suchas CO₂. In specific embodiments, a method of power generation accordingto the invention can comprise introducing a carbon containing fuel, O₂,and a CO₂ circulating fluid into a transpiration cooled combustor.Specifically, the CO₂ can be introduced at a pressure of at least about8 MPa (preferably at least about 12 MPa) and a temperature of at leastabout 200° C. (preferably at least about 400° C.). The method furthercan comprise combusting the fuel to provide a combustion product streamcomprising CO₂. Particularly, the combustion product stream can have atemperature of at least about 800° C. Further, the method can compriseexpanding the combustion product stream across a turbine to generatepower, the turbine having an inlet for receiving the combustion productstream and an outlet for release of a turbine discharge streamcomprising CO₂. Preferably, the pressure ratio of the combustion productstream at the inlet compared to the turbine discharge stream at theoutlet can be less than about 12. In specific embodiments, it can bedesirable for the CO₂ to be introduced into the combustor at a pressureof at least about 10 MPa, a pressure of at least about 20 MPa, atemperature of at least about 400° C., or a temperature of at leastabout 700° C. Even further possible processing parameters are describedherein.

In some embodiments, the CO₂ circulating fluid can be introduced to thetranspiration cooled combustor as a mixture with one or both of the O₂and the carbon containing fuel. In other embodiments, the CO₂circulating fluid can be introduced to the transpiration cooledcombustor as all or part of a transpiration cooling fluid directedthrough one or more transpiration fluid supply passages formed in thetranspiration cooled combustor. In specific embodiments, the CO₂circulating fluid can be directed into the combustor only as thetranspiration fluid.

The combustion may be characterized specifically by the actualcombustion temperature. For example, combusting can be carried out at atemperature of at least about 1,500° C. In other embodiments, combustingcan be carried out at a temperature of about 1,600° C. to about 3,300°C.

The invention also may be characterized by the purity of the O₂ in theO₂ stream. For example, in some embodiments, ambient air may be useful.In specific embodiments, however, it can be beneficial to purify theoxygen content. For example, the O₂ can be provided as a stream whereinthe molar concentration of the O₂ is at least 85%. Even further specificconcentrations are described herein.

In specific embodiments, the combustion product stream can have atemperature of at least about 1,000° C. Moreover, the combustion productstream can have a pressure that is at least about 90% of the pressure ofthe CO₂ introduced into the combustor or is at least about 95% of thepressure of the CO₂ introduced into the combustor.

In some embodiments, the pressure ratio of the combustion product streamat the inlet of the turbine compared to the turbine discharge stream atthe outlet of the turbine can be about 1.5 to about 10 or can be about 2to about 8. Even further possible ratios are provided herein.

The invention may be characterized by the ratio of the specificmaterials introduced into the combustion chamber. For example, the ratioof CO₂ in the CO₂ circulating fluid to carbon in the fuel introduced tothe combustor, on a molar basis, can be about 10 to about 50 or can beabout 10 to about 30. Even further possible ratios are provided herein.

The invention further may be characterized in that at least a portion ofthe CO₂ in the turbine discharge stream can be recycled and reintroducedinto the combustor. At least a portion of the CO₂ may be discharged fromthe system (such as for sequestration or other disposal), for examplethrough a pipeline.

In specific embodiments, the CO₂ in the turbine discharge stream can bein a gaseous state. Particularly, the turbine discharge stream can havea pressure of less than or equal to 7 MPa.

In other embodiments, the inventive methods further can comprise passingthe turbine discharge stream through at least one heat exchanger thatcools the turbine discharge stream and provides a CO₂ circulating fluidstream having a temperature of less than about 200° C. This can beuseful for providing the CO₂ circulating fluid stream under conditionsthat can facilitate removal of one or more secondary components (i.e.,components other than CO₂). In specific embodiments, this can comprisepassing the turbine discharge stream through a series of at least twoheat exchangers. More specifically, the first heat exchanger in theseries can receive the turbine discharge stream and reduce thetemperature thereof, the first heat exchanger being formed of a hightemperature alloy that withstands a temperature of at least about 900°C.

The inventive methods also can comprise performing one or moreseparation steps on the CO₂ circulating fluid stream to remove one ormore secondary components that are present in the circulating fluidstream in addition to CO₂, as noted above. Specifically, the one or moresecondary components may comprise water.

The inventive methods also may comprise pressurizing a CO₂ stream. Forexample, after expanding of the combustion product stream and cooling ofthe turbine discharge stream, it can be beneficial to pressurize thestream for recycle back to the combustor. Specifically, the methods cancomprise passing the CO₂ circulating fluid stream through one or morecompressors (e.g., pumps) to pressurize the CO₂ circulating fluid streamto a pressure of at least about 8 MPa. This further may comprise passingthe CO₂ circulating fluid stream through a series of at least twocompressors to pressurize the CO₂ circulating fluid stream. In certainembodiments, the CO₂ circulating fluid stream can be pressurized to apressure of at least about 15 MPa. Even further pressure ranges may bedesirable, as otherwise described herein. In other embodiments, thepressurized CO₂ circulating fluid stream specifically can be provided ina supercritical fluid state. In some embodiments, at least a portion ofthe CO₂ in the pressurized CO₂ circulating fluid stream can beintroduced into a pressurized pipeline for sequestration (or otherdisposal, as already noted above).

In addition to pressurizing, the inventive methods also can compriseheating the previously cooled CO₂ circulating fluid stream forintroduction back into the combustor (i.e., recycling of the CO₂circulating fluid stream). In some embodiments, this can compriseheating the pressurized CO₂ circulating fluid stream to a temperature ofat least about 200° C., at least about 400° C., or at least about 700°C. In certain embodiments, the pressurized CO₂ circulating fluid streamcan be heated to a temperature that is less than the temperature of theturbine discharge stream by no more than about 50° C. Even furtherpossible temperature ranges are provided herein. Specifically, suchheating can comprise passing the pressurized CO₂ circulating fluidstream through the same heat exchanger(s) used to cool the turbinedischarge stream. Such heating also can comprise input of heat from anexternal source (i.e., other than heat re-captured from the heatexchangers). In specific embodiments, heating can comprise the use ofheat withdrawn from an O₂ separation unit. Preferably, this additionalheat is introduced at the cold end of the heat exchanger unit (or, whena series of heat exchangers is used, prior to the heat exchanger in theseries working over the highest temperature range).

In certain embodiments, the invention can be characterized by nature ofthe combustion product stream, which can allow for the optionalimplementation of multiple turbines. For example, in some embodiments,the combustion product stream can be a reducing fluid comprising one ormore combustible components (e.g., components selected from the groupconsisting of H₂, CO, CH₄, H₂S, NH₃, and combinations thereof). This maybe controlled by the ratio of O₂ to fuel used. In some embodiments, thecombustion product stream steam may contain fully oxidized components,such as CO₂, H₂O, and SO₂, as well as the reduced components listedabove. The actual composition achieved can depend on the ratio of O₂ tofuel used in the feed to the transpiration combustor. More specifically,the turbine used in such embodiments can comprise two or more units eachhaving an inlet and an outlet. In specific embodiments, the turbineunits can be operated such that the operating temperature at the inletof each unit is substantially the same. This can comprise adding anamount of O₂ to the fluid stream at the outlet of the first turbine unit(or the preceding turbine unit where three or more units are used).Provision of the O₂ can allow for combustion of the one or morecombustible components described above, which raises the temperature ofthe stream prior to entry to the next turbine in the series. Thisresults in the ability to maximize the power produced from thecombustion gases in the presence of the circulating fluid.

In other embodiments, the turbine discharge stream can be an oxidizingfluid. For example, the turbine discharge stream may comprise an excessamount of O₂.

In some embodiments, the invention can be characterized by the state ofthe various streams. For example, after the step of expanding thecombustion product stream across the turbine, the turbine dischargestream can be in a gaseous state. This gas can be passed through atleast one heat exchanger to cool the gaseous turbine discharge streamfor separation of the CO₂ from any secondary components. Thereafter, atleast a portion of the separated CO₂ can be pressurized and transformedinto a supercritical fluid state and again be passed through the sameheat exchanger(s) to heat the CO₂ for recycling into the combustor. Inspecific embodiments, the temperature difference between the temperatureof the turbine discharge stream entering the heat exchanger (or thefirst heat exchanger when a series is used) from the expanding step andthe temperature of the heated, pressurized, supercritical fluid CO₂exiting the same heat exchanger for recycling into the combustor can beless than about 50° C.

As noted above, the fluid stream exiting from the fuel combustor maycomprise the CO₂ circulating fluid as well as one or more furthercomponents, such as combustion products. In some embodiments, it can beuseful to recycle at least a portion of the CO₂ and reintroduce it intothe fuel combustor. Thus, the circulating fluid can be a recycle fluid.Of course, CO₂ from an external source could be used as the circulatingfluid. The turbine exhaust may be cooled in an economizer heatexchanger, and the withdrawn heat can be used to heat the high pressurerecycle CO₂. The cooled turbine exhaust leaving the low temperature endof the heat exchanger can contain components derived from the fuel orthe combustion process, such as H₂O, SO₂, SO₃, NO, NO₂, Hg, and HCl. Infurther embodiments, these components can be removed from the streamusing suitable methods. Other components in this stream may compriseinert gaseous impurities derived from the fuel or oxidant such as N₂,Argon (Ar), and excess O₂. These may be removed by separate suitableprocesses. In further embodiments, the turbine exhaust must be at apressure which is less than the condensing pressure of CO₂ in theturbine exhaust at the temperature of available cooling means so that noCO₂ liquid phase can form when the turbine exhaust is cooled as thiswill allow efficient separation of water as liquid from the gaseous CO₂which will contain the minimal amount of water vapor to allow water tobe condensed. In further embodiments, the purified CO₂ can now becompressed to produce the high pressure recycle CO₂ circulating fluidstream together with at least a portion of the CO₂ in the fluidrepresenting oxidized carbon derived from carbon in the fuel feed to thecombustor, which can be introduced into a pressurized pipeline forsequestration. The ability to transfer CO₂ directly from the combustionprocess into a pressurized pipeline with minimal further treatment orcompression due to the high pressure of the turbine exhaust stream is adistinct advantage over conventional methods where CO₂ is recovered atclose to atmospheric pressure (i.e., around 0.1 MPa) or is emitted tothe atmosphere. Moreover, the CO₂ for sequestration according to thepresent invention may be transferred in a manner that is more efficientand economical than heretofore known.

The specific heat of the recycle CO₂ fluid entering the heat exchanger,ideally at above the critical pressure, is high and reduces as thetemperature rises. It is particularly beneficial for at least a portionof the heat at the lowest temperature levels to be derived from anexternal source. This could for example be a low pressure steam supplywhich would provide heat on condensation. In further embodiments thissource of heat could be derived from the operation of the aircompressors used in the cryogenic air separation plant supplying oxidantto the combustor in the adiabatic mode with no inter-cooling andextraction of the heat of compression with a closed cycle stream of heattransfer fluid used to provide heat to the recycle CO₂ stream.

In one embodiment, a method of power generation according to the presentinvention can comprise the following steps:

introducing a fuel, O₂, and a CO₂ circulating fluid into a combustor,the CO₂ being introduced at a pressure of at least about 8 MPa and atemperature of at least about 200° C.;

combusting the fuel to provide a combustion product stream comprisingCO₂, the combustion product stream having a temperature of at leastabout 800° C.;

expanding the combustion product stream across a turbine to generatepower, the turbine having an inlet for receiving the combustion productstream and an outlet for release of a turbine discharge streamcomprising CO₂, wherein the pressure ratio of the combustion productstream at the inlet compared to the turbine discharge stream at theoutlet is less than about 12;

withdrawing heat from the turbine discharge stream by passing theturbine discharge stream through a heat exchange unit to provide acooled turbine discharge stream;

removing from the cooled turbine discharge stream one or more secondarycomponents that are present in the cooled turbine discharge stream inaddition to CO₂ to provide a purified, cooled turbine discharge stream;

compressing the purified, cooled turbine discharge stream with a firstcompressor to a pressure above the CO₂ critical pressure to provide asupercritical CO₂ circulating fluid stream;

cooling the supercritical CO₂ circulating fluid stream to a temperaturewhere its density is at least about 200 kg/m³;

passing the supercritical, high density CO₂ circulating fluid through asecond compressor to pressurize the CO₂ circulating fluid to thepressure required for input to the combustor;

passing the supercritical, high density, high pressure CO₂ circulatingfluid through the same heat exchange unit such that the withdrawn heatis used to increase the temperature of the CO₂ circulating fluid;

supplying an additional quantity of heat to the supercritical, highdensity, high pressure CO₂ circulating fluid so that the differencebetween the temperature of the CO₂ circulating fluid exiting the heatexchange unit for recycle to the combustor and the temperature of theturbine discharge stream is less than about 50° C.; and

recycling the heated, supercritical, high density CO₂ circulating fluidinto the combustor.

In particular embodiments, the systems and methods may be particularlyuseful for combining with existing power systems and methods (e.g.,convention coal fired power stations, nuclear reactors, and othersystems and methods that may make use of conventional boiler systems).Thus, in some embodiments, between the expanding step and thewithdrawing step described above, the inventive methods can comprisepassing the turbine discharge stream through a second heat exchangeunit. Such second heat exchange unit can use heat from the turbinedischarge stream to heat one or more streams derived from a steam powersystem (e.g., a conventional boiler system, including coal fired powerstations and nuclear reactor). The thus heated steam streams then can bepassed through one or more turbines to generate power. The streamsexiting the turbines can be processed by cycling back through thecomponents of the conventional power system (e.g., the boiler).

In further embodiments, the inventive method may be characterized by oneor more of the following:

cooling the turbine discharge stream to a temperature below its waterdew point;

further cooling the turbine discharge stream against an ambienttemperature cooling medium;

condensing water together with the one or more secondary components toform a solution comprising one or ore of H₂SO₄, HNO₃, HCl, and mercury;

pressurizing the cooled turbine discharge stream to a pressure of lessthan about 15 MPa;

withdrawing a product CO₂ stream from the supercritical, high density,high pressure CO₂ circulating fluid stream prior to passing through theheat exchange unit;

using as the fuel a stream of partial combustion products;

combusting a carbon containing fuel with O₂ in the presence of a CO₂circulating fluid, the carbon containing fuel, O₂, and CO₂ circulatingfluid being provided in ratios such that the carbon containing fuel isonly partially oxidized to produce the partially oxidized combustionproduct stream comprising an incombustible component, CO₂, and one ormore of H₂, CO, CH₄, H₂S, and NH₃;

providing the carbon containing fuel, O₂, and CO₂ circulating fluid inratios such that the temperature of the partially oxidized combustionproduct stream is sufficiently low that all of the incombustiblecomponent in the stream is in the form of solid particles;

passing the partially oxidized combustion product stream through one ormore filters;

using the filter to reduce the residual amount of incombustiblecomponent to less than about 2 mg/m³ of the partially oxidizedcombustion product;

using coal, lignite, or petroleum coke as the fuel;

providing a particulate fuel as a slurry with CO₂;

In further embodiments, the invention may be described as relating to amethod of power generation comprising the following steps:

introducing a carbon containing fuel, O₂, and a CO₂ circulating fluidinto a transpiration cooled combustor, the CO₂ being introduced at apressure of at least about 8 MPa and a temperature of at least about200° C.;

combusting the fuel to provide a combustion product stream comprisingCO₂, the combustion product stream having a temperature of at leastabout 800° C.;

expanding the combustion product stream across a turbine to generatepower, the turbine having an inlet for receiving the combustion productstream and an outlet for release of a turbine discharge streamcomprising CO₂, wherein the pressure ratio of the combustion productstream at the inlet compared to the turbine discharge stream at theoutlet is less than about 12;

passing the turbine discharge stream through a series of at least twoheat exchangers that withdraw heat from the turbine discharge stream andprovide the CO₂ circulating fluid stream;

removing from the CO₂ circulating fluid stream one or more secondarycomponents that are present in the circulating fluid stream in additionto CO₂;

passing the CO₂ circulating fluid stream through a series of at leasttwo compressors that increases the pressure of the CO₂ circulating fluidto at least about 8 MPa and transforms the CO₂ in the circulating fluidfrom a gaseous state to a supercritical fluid state; and

passing the supercritical CO₂ circulating fluid through the same seriesof at least two heat exchangers that uses the withdrawn heat to increasethe temperature of the CO₂ circulating fluid to at least about 200° C.(or, optionally, to a temperature that is less than the temperature ofthe turbine discharge stream by no more than about 50° C.). Thisspecifically may comprise introduction of additional heat from anexternal heat source (i.e., a source of heat not derived directly fromthe passage of the turbine discharge stream through the heatexchanger(s)).

In further embodiments, the invention may be characterized as providinga high efficiency method of generating power from combustion of a carboncontaining fuel with no atmospheric release of CO₂. Specifically, themethod can comprise the following steps:

introducing the carbon containing fuel, O₂, and a recycled CO₂circulating fluid into a transpiration cooled combustor in a definedstoichiometric ratio, the CO₂ being introduced at a pressure of at leastabout 8 MPa and a temperature of at least about 200° C.;

combusting the fuel to provide a combustion product stream comprisingCO₂, the combustion product stream having a temperature of at leastabout 800° C.;

expanding the combustion product stream across a turbine to generatepower, the turbine having an inlet for receiving the combustion productstream and an outlet for release of a turbine discharge streamcomprising CO₂, wherein the pressure ratio of the combustion productstream at the inlet compared to the turbine discharge stream at theoutlet is less than about 12;

passing the turbine discharge stream through a series of at least twoheat exchangers that withdraw heat from the turbine discharge stream andprovide the CO₂ circulating fluid stream;

passing the CO₂ circulating fluid stream through a series of at leasttwo compressors that increases the pressure of the CO₂ circulating fluidto at least about 8 MPa and transforms the CO₂ in the circulating fluidfrom a gaseous state to a supercritical fluid state;

passing the CO₂ circulating fluid stream through a separation unitwherein the stoichiometrically required amount of CO₂ is recycled anddirected to the combustor and any excess CO₂ is withdrawn withoutatmospheric release; and

passing the recycled CO₂ circulating fluid through the same series of atleast two heat exchangers that uses the withdrawn heat to increase thetemperature of the CO₂ circulating fluid to at least about 200° C. priorto introduction into the combustor (or, optionally, to a temperaturethat is less than the temperature of the turbine discharge stream by nomore than about 50° C.);

wherein the efficiency of the combustion is greater than 50%, saidefficiency being calculated as the ratio of the net power generated inrelation to the total lower heating value thermal energy for the carboncontaining fuel combusted to generate the power.

In another aspect, the invention can be described as provide a powergeneration system. Specifically, a power generation system according tothe invention can comprise a transpiration cooled combustor, a powerproduction turbine, at least one heat exchanger, and at least onecompressor.

In specific embodiments, the transpiration cooled combustor can have atleast one inlet for receiving a carbon-containing fuel, O₂, and a CO₂circulating fluid stream. The combustor further can have at least onecombustion stage that combusts the fuel in the presence of the CO₂circulating fluid and provides a combustion product stream comprisingCO₂ at a defined pressure (e.g., at least about 8 MPa) and temperature(e.g., at least about 800° C.).

The power production turbine can be in fluid communication with thecombustor and can have an inlet for receiving the combustion productstream and an outlet for release of a turbine discharge streamcomprising CO₂. The turbine can be adapted to control pressure drop suchthat the ratio of the pressure of the combustion product stream at theinlet compared to the turbine discharge stream at the outlet is lessthan about 12.

The at least one heat exchanger can be in fluid communication with theturbine for receiving the turbine discharge stream. The heatexchanger(s) can transfer heat from the turbine discharge stream to theCO₂ circulating fluid stream.

The at least one compressor can be in fluid communication with the atleast one heat exchanger. The compressor(s) can be adapted forpressurizing the CO₂ circulating fluid stream to a desired pressure.

In addition to the foregoing, a power generation system according to theinvention further can comprise one or more separation devices positionedbetween the at least one heat exchanger and the at least one compressor.Such separation device(s) can be useful for removal of one or moresecondary components present in the CO₂ circulating fluid in addition tothe CO₂.

Still further, the power generation system can comprise an O₂ separationunit that includes one or more components that generates heat. Thus, thepower generation system also can comprise one or more heat transfercomponents that transfers heat from the O₂ separation unit to the CO₂circulating fluid upstream from the combustor. Optionally, the powergeneration system can comprise an external heat source. This could forexample be a low pressure steam supply which would provide heat oncondensation. The power generation system thus could include one or moreheat transfer components that transfers heat from the steam to the CO₂circulating fluid upstream from the combustor.

In further embodiments, a power generation system of the invention mayinclude one or more of the following:

a first compressor adapted to compress the CO₂ circulating fluid streamto a pressure that is above the CO₂ critical pressure;

a second compressor adapted to compress the CO₂ circulating fluid streamto a pressure required for input to the combustor;

a cooling device adapted to cool the CO₂ circulating fluid stream to atemperature where its density is greater than about 200 kg/m³;

one or more heat transfer components that transfers heat from anexternal source to the CO₂ circulating fluid upstream from the combustorand downstream from the second compressor;

a second combustor located upstream from and in fluid communication withthe transpiration cooled combustor;

one or more filters or separation devices located between the secondcombustor and the transpiration cooled combustor;

a mixing device for forming a slurry of a particulate fuel material witha fluidizing medium;

a milling device for particularizing a solid fuel.

In other embodiments, the present invention can provide a powergeneration system that may comprise the following: one or more injectorsfor providing fuel, a CO₂ circulating fluid, and an oxidant; atranspiration cooled combustor having at least one combustion stage thatcombusts the fuel and provides an exhaust fluid stream at a temperatureof at least about 800° C. and a pressure of at least about 4 MPa(preferably at least about 8 MPa); a power production turbine having aninlet and an outlet and wherein power is produced as the fluid streamexpands, the turbine being designed to maintain the fluid stream at adesired pressure such that the ratio of the pressure of the fluid streamat the inlet versus the outlet is less than about 12; a heat exchangerfor cooling the fluid stream leaving the turbine outlet and for heatingthe CO₂ circulating fluid; and one or more devices for separating thefluid stream exiting the heat exchanger into CO₂ and one or more furthercomponents for recovery or disposal. In further embodiments, the powergeneration system may also comprise one or more devices for deliveringat least a portion of the CO₂ separated from the fluid stream into apressurized pipeline.

In specific embodiments, a system according to the invention maycomprise one or more components as described herein retrofit with anconventional power production system, such as a coal fired powerstation, a nuclear reactor, or the like. For example, a power systemcould comprise two heat exchange units (e.g., a primary heat exchangeunit and a secondary heat exchange unit). The primary heat exchange unitcould be substantially a unit as otherwise described herein, and thesecondary heat exchange unit could be a unit useful for transferringheat from the turbine discharge stream to one or more steam streams(e.g., from a boiler associated with the conventional power productionsystem) to superheat the steam streams. Thus, a power generation systemaccording to the invention may comprise a secondary heat exchange unitlocated between and in fluid communication with the turbine and theprimary heat exchange unit. The power generation system likewise cancomprise a boiler in fluid communication with the secondary heatexchange unit via at least one steam stream. Still further, the powergeneration system can comprise at least one further power productionturbine having an inlet for receiving the at least one steam stream fromthe secondary heat exchange unit. Thus, the system may be described ascomprising a primary power production turbine and a secondary powerproduction turbine. The primary power production turbine may be theturbine in fluid communication with the inventive combustor. Thesecondary power production turbine may be the turbine in fluidcommunication with a steam stream, particularly a superheated steamstream that is superheated with heat from the discharge stream from theprimary power production turbine. Such a system retrofit with one ormore components from a convention power production system is describedherein, particularly in relation to FIG. 12 and Example 2. The use ofthe terms primary power production turbine and secondary powerproduction turbine should not be construed as limiting the scope of theinvention and are only used to provide clarity of description.

In another aspect of the invention an external stream may be heated inthe high temperature end of the heat exchanger by heat transfer from thecooling turbine exhaust stream and, as a result, the high pressurerecycle stream will leave the heat exchanger and enter the combustor ata lower temperature. In this case, the amount of fuel burned in thecombustor may be increased so that the turbine inlet temperature ismaintained. The heating value of the extra fuel burned is equivalent tothe extra heat load imposed on the heat exchanger.

In some embodiments, the invention can be characterized as providing aprocess plant producing shaft power from the circulation of apredominantly CO₂ circulating fluid. In further embodiments, theinvention provides processes in which certain conditions may be met. Inspecific embodiments, the invention further may be characterized by oneor more of the following actions or devices useful for carrying out suchactions:

compressing the CO₂ circulating fluid to a pressure in excess of thecritical pressure of CO₂;

directly combusting a solid, liquid, or gaseous hydro-carbonaceous fuelin substantially pure O₂ with provision for mixing a CO₂ richsupercritical recycle fluid to achieve a required power turbine inlettemperature—e.g., greater than about 500° C. (or other temperature rangeas described herein);

expanding a supercritical stream formed of combustion products andrecycled CO₂ rich fluid in a turbine with production of shaft power,particularly expanding to a pressure that is above about 2 MPa and isbelow the pressure at which a CO₂ liquid phase appears when the fluid iscooled to a temperature consistent with the use of ambient temperaturecooling means (e.g., about 7.3-7.4 MPa);

introducing a turbine exhaust into a heat exchanger in which the turbineexhaust is cooled, and the heat is transferred to a recycled CO₂ richsupercritical fluid;

cooling a CO₂ containing stream leaving a heat exchanger against anambient temperature cooling means and separating a water liquid phasethat contains at least minor concentrations of CO₂ and a gaseous CO₂phase that contains at least a minor concentration of water vapor;

carrying out a water separation in a manner that allows a desiredresidence time (e.g., up to 10 seconds) with intimate contact betweengaseous CO₂ and liquid water or a weak acid phase such that reactionsinvolving SO₂, SO₃, H₂O, NO, NO₂, O₂, and/or Hg can take place resultingin the conversion of greater than 98% of sulfur present in a stream toH₂SO₄ and the conversion of greater than 90% of nitrogen oxides presentin a stream to HNO₃, and for the conversion of greater than 80% ofmercury in a stream to soluble mercury compounds;

separating non condensable components (such as N₂, Ar, and O₂) from agaseous CO₂ phase by cooling to a temperature close to the CO₂ freezingpoint with a gas/liquid phase separation leaving the N₂, Ar, and O₂predominantly in the gas phase;

compressing a purified gaseous CO₂ stream in a gas compressor to apressure at which cooling by ambient temperature cooling means willyield a high density CO₂ fluid (e.g., with a density of at least about200 kg/m³, preferably at least about 300 kg/m³, or more preferably atleast about 400 kg/m³);

cooling compressed CO₂ with ambient cooling means to form a high densityCO₂ supercritical fluid (e.g., with a density of at least about 200kg/m³, preferably at least about 300 kg/m³, or more preferably at leastabout 400 kg/m³);

compressing a high density CO₂ fluid in a compressor to a pressure abovethe critical pressure of CO₂;

separating a high pressure CO₂ stream into two separate streams—one thatenters the cold end of a heat exchanger and a second that is heatedusing an external heating source available at a temperature below about250° C.;

facilitating efficient heat transfer (including the use of an optionalexternal heat source) such that the difference between the temperatureof a turbine discharge stream entering the hot end of a heat exchangerand the temperature of a recycle CO₂ circulating fluid leaving the hotend of the same heat exchanger is less than about 50° C. (or othertemperature threshold as described herein);

compressing a CO₂ circulating fluid to a pressure of about 8 MPa toabout 50 MPa (or other pressure range as described herein);

mixing of an O₂ stream with at least a portion of a recycled CO₂circulating fluid stream and a carbon containing fuel stream to form asingle fluid stream (or slurry if a powdered, solid fuel is used), whichis below the auto-ignition temperature of the fuel, and the proportionsof which are adjusted to give an adiabatic flame temperature of about1,200° C. to 3,500° C. (or other temperature range as described herein);

mixing at least a portion of a recycled CO₂ circulating fluid withcombustion products to form a mixed fluid stream at a temperature in therange of about 500° C. to 1,600° C. (or other temperature range asdescribed herein);

producing a turbine discharge stream having a pressure of about 2 MPa toabout 7.3 MPa (or other pressure range as described herein);

externally heating a portion of a high pressure CO₂ circulating fluidstream using heat of compression derived from the operation of one ormore air compressors of a cryogenic O₂ plant (particularly in theadiabatic mode) and/or a CO₂ compressor (particularly in the adiabaticmode), the heat being transferred by circulation of a suitable heattransfer fluid (including the CO₂ fluid itself);

heating one or more external fluid streams in a heat exchanger withequivalent extra fuel being burned in a burner, wherein one or more ofthe external fluid streams may comprise steam, which can be super heatedin the heat exchanger;

using heat supplied by condensing steam provided from an external sourceto externally heat a portion of a recycled CO₂ circulating fluid stream;

cooling in a heat exchanger a CO₂ containing stream (which leaves thecold end of the heat exchanger) to provide heat for heating anexternally provided fluid stream;

providing an O₂ feed stream wherein the molar concentration of the O₂ isat least about 85% (or other concentration range as described herein);

operating a combustor such that the concentration of O₂ in a total gasstream leaving the combustor (i.e., a combustion product stream) andentering a turbine is greater than about 0.1% molar;

carrying out a power production process such that only one powerproducing turbine is used;

carrying out a power production process such that only one combustor isused to substantially completely combust the carbon containing fuelinput into the combustor;

operating a combustor such that the quantity of O₂ in the O₂ streamentering the combustor is below the quantity required for stoichiometriccombustion of the fuel stream entering the combustor and thus causingproduction of one or both of H₂ and carbon monoxide (CO) in thecombustion product stream; and

carrying out a process using two or more turbines each having a definedexit pressure wherein one or both of H₂ and CO are present in thedischarge stream leaving the first turbine (and subsequent turbines, ifapplicable, with the exception of the final turbine in the turbineseries) and part or all of the H₂ and CO is combusted by the addition ofa stream of O₂ before the inlet of the second and subsequent turbines toraise the operating temperature of each of the second or more turbinesto a higher value resulting in an excess O₂ in the exit stream from thelast turbine, such excess being greater than bout 0.1% molar.

In further embodiments, the present invention may provide one or more ofthe following:

heating a CO₂ circulating fluid in a heat exchange system against thecooling turbine exhaust stream such that the turbine exhaust stream iscooled to a temperature below its water dew point;

cooling the turbine exhaust stream against an ambient temperaturecooling medium and condensing water together with fuel and combustionderived impurities comprising H₂SO₄, HNO₃, HCl, and other impuritiessuch as Hg and other metals in the form of ionic compounds in solution;

compressing the purified CO₂ circulating fluid to a pressure above itscritical pressure but below 10 MPa in a first compressor;

cooling the circulating fluid to a point where its density is greaterthan 600 kg/m3;

compressing the high density CO₂ circulating fluid in a compressor tothe pressure required to overcome pressure drop in the system and feedthe circulating CO₂ fluid into the combustion chamber;

removing a product CO₂ product stream containing substantially all ofthe CO₂ formed by combustion of carbon in the fuel stream, the CO₂stream being taken from either the discharge flow of the firstcompressor or the second compressor;

supplying an additional quantity of heat to the CO₂ circulating fluid ata temperature level which is above the water dew-point of the coolingturbine exhaust stream either directly to the heat exchanger or byheating a side-stream comprising part of the CO₂ circulating fluid sothat the temperature difference between the circulating CO₂ fluid andthe turbine exhaust at the hot end of the heat exchanger is less that50° C.;

using a fuel comprising a carbon containing fuel having an incombustibleresidue which is partially oxidized with O₂ in a transpiration cooledcombustor to produce a stream comprising H₂, CO, CH₄, H₂S, NH₃ andincombustible residue, the combustor being fed with part of thecirculating CO₂ fluid to cool the partially oxidized combustion productsto a temperature of 500° C. to 900° C. where the ash is present as solidparticulate which can be completely removed from the outlet fluid streamby a filtration system;

providing for a temperature difference between the cooling turbineexhaust stream and the heating circulating CO₂ fluid stream at the pointat which the side-stream flow remixes with the separately heatedcirculating CO₂ fluid flow that is between 10° C. and 50° C.;

providing for a pressure of the turbine exhaust stream leaving the coldend of the heat exchanger such that no liquid CO₂ is formed when thisstream is cooled prior to water and impurity separation;

using least part of the turbine exhaust stream to superheat multiplesteam streams derived from steam power systems associated withconventional boiler systems and nuclear reactors;

providing additional low level heat to the circulating CO₂ stream assteam at one or more pressure levels taken from an external steam sourcesuch as a power station;

using the expander exhaust stream leaving the cold end of the heatexchanger system to provide heating for at least part of the condensateleaving the steam condenser of the steam power generation system;

providing additional low level heat for the circulating CO₂ stream fromthe hot exhaust of an open cycle gas turbine;

passing a partially oxidized coal derived gas plus CO₂ as fuel to asecond combustor for complete combustion;

operating a single combustor with an O₂ to fuel ratio such that part ofthe fuel is oxidized to oxidation products comprising CO₂, H₂O, and SO₂and the rest of the fuel is oxidized to components comprising H₂, CO,and H₂S;

operating two turbines which over the total required pressure ratio withO₂ injected into the discharge flow of the first turbine to combust thereduced components to reheat the intermediate pressure flow to a highertemperature before it is expanded through the second turbine.

Even further embodiments are encompassed by the present invention asdescribed in relation to the various figures and/or as disclosed in thefurther description of the invention provided herein.

BRIEF DESCRIPTION OF THE DRAWINGS

Having thus described the invention in general terms, reference will nowbe made to the accompanying drawings, which is not necessarily drawn toscale, and wherein:

FIG. 1 is a schematic illustration of a transpiration-cooled combustorapparatus that may be used according to certain embodiments of thepresent disclosure;

FIG. 2 is a schematic illustration of an exemplary cross-section of awall of a transpiration member in a combustor apparatus that may be usedin certain embodiments of the present disclosure;

FIG. 3A and FIG. 3B schematically illustrate a hot fit process for atranspiration member assembly of a combustor apparatus that may be usedin certain embodiments of the present disclosure;

FIG. 4 schematically illustrates a combustion product contaminantremoval apparatus that may be useful according to certain embodiments ofthe present disclosure;

FIG. 5 is a flow diagram illustrating a power cycle according to oneembodiment of the present disclosure;

FIG. 6 is a flow diagram illustrating the flow of a CO₂ circulatingfluid through a separation unit according to one embodiment of thepresent disclosure;

FIG. 7 is a flow diagram illustrating pressurization using a series oftwo or more compressors or pumps in a pressurization unit according toone embodiment of the present disclosure;

FIG. 8 is a flow diagram illustrating a heat exchanger unit according toone embodiment of the present disclosure wherein three individual heatexchangers are used in series;

FIG. 9 is a flow diagram illustrating a turbine unit utilizing twoturbines operated in series in the reducing mode according to oneembodiment of the present disclosure;

FIG. 10 is a flow diagram illustrating a system and method for powerproduction according to one embodiment of the present invention usingtwo combustors;

FIG. 11 is a flow diagram illustrating a specific example of a systemand method for power production according to one embodiment of thepresent disclosure; and

FIG. 12 is a flow diagram illustrating another example of a system andmethod for power production incorporating a conventional coal firedboiler according to an embodiment of the present disclosure.

DETAILED DESCRIPTION OF THE INVENTION

The invention now will be described more fully hereinafter throughreference to various embodiments. These embodiments are provided so thatthis disclosure will be thorough and complete, and will fully convey thescope of the invention to those skilled in the art. Indeed, theinvention may be embodied in many different forms and should not beconstrued as limited to the embodiments set forth herein; rather, theseembodiments are provided so that this disclosure will satisfy applicablelegal requirements. As used in the specification, and in the appendedclaims, the singular forms “a”, “an”, “the”, include plural referentsunless the context clearly dictates otherwise.

The present invention provides systems and methods for producing powerthrough use of a high efficiency fuel combustor (such as a transpirationcooled combustor) and an associated circulating fluid (such as a CO₂circulating fluid). The circulating fluid is provided in the combustoralong with an appropriate fuel, any necessary oxidant, and anyassociated materials that may be useful for efficient combustion. Inspecific embodiments, the methods can be carried out using a combustorthat operates at very high temperatures (e.g., in the range of about1,600° C. to about 3,300° C., or other temperature ranges as disclosedherein), and the presence of the circulating fluid can function tomoderate the temperature of a fluid stream exiting the combustor so thatthe fluid stream can be utilized in energy transfer for powerproduction. Specifically, a combustion product stream can be expandedacross at least one turbine to generate power. The expanded gas streamcan be cooled to remove various components from the stream, such aswater, and heat withdrawn from the expanded gas stream can be used toheat the CO₂ circulating fluid. The purified circulating fluid streamcan then be pressurized and heated for recycle through the combustor. Ifdesired, part of the CO₂ from the combustion product stream (i.e.,arising from CO₂ formed by combustion of the carbon containing fuel inthe presence of oxygen) can be drawn off for sequestration or otherdisposal, such as transfer to a CO₂ pipeline. The system and methods canmake use of specific process parameters and components to maximizeefficiency of the system and method, particularly while avoidingreleasing CO₂ to the atmosphere. As particularly described herein, thecirculating fluid is exemplified by the use of CO₂ as the circulatingfluid. While use of a CO₂ circulating fluid is an advantageousembodiment according to the invention, such disclosure should not beconstrued as necessarily limiting the scope of the circulating fluidthat may be used in the invention unless otherwise stated.

In certain embodiments, a power generation system according to theinvention can uses a circulating fluid comprising predominantly CO₂. Inother words, the chemical nature of the circulating fluid immediatelyprior to input into the combustor is such that the circulating fluidcomprises predominately CO₂. In this sense, the word “predominately” canmean the fluid comprises at least about 90% by molar concentration, atleast about 91% by molar concentration, at least about 92% by molarconcentration, at least about 93% by molar concentration, at least about94% by molar concentration, at least about 95% by molar concentration,at least about 96% by molar concentration, at least about 97% by molarconcentration, at least about 98% by molar concentration, or at leastabout 99% by molar concentration CO₂. The circulating fluid immediatelyprior to entering the combustor preferably comprises substantially onlyCO₂. In this sense, the phrase “substantially only” can mean at leastabout 99.1% by molar concentration, at least about 99.25% by molarconcentration, at least about 99.5% by molar concentration, at leastabout 99.75% by molar concentration, at least about 99.8% by molarconcentration, or at least about 99.9% by molar concentration CO₂. Inthe combustor, the CO₂ can comingle with one or more further componentsthat can be derived from the fuel, any oxidant, and any derivatives fromthe fuel combustion. Thus, the circulating fluid exiting the combustor,which can be described herein as a combustion product stream, maycomprise CO₂ along with lesser amounts of other materials, such as H₂O,O₂, N₂, Ar, SO₂, SO₃, NO, NO₂, HCl, Hg, and traces of other componentsthat can be derived from the combustion process (e.g., particulates,such as ash or liquefied ash), including further combustibles. Asdescribed in greater detail below, the combustion process can becontrolled such that the nature of the fluid stream can be eitherreducing or oxidizing, which can provide particularly describedbenefits.

The systems and methods of the invention can incorporate one or morecombustors useful for combustion of a suitable fuel, as describedherein. Preferably, at least one combustor used according to the presentinvention is a high efficiency combustor capable of providingsubstantially complete combustion of a fuel at a relatively highcombustion temperature. High temperature combustion can be particularlyuseful to provide for substantially complete combustion of the fuel andthus maximize efficiency. In various embodiments, high temperaturecombustion can mean combustion at a temperature of at least about 1,200°C., at least about 1,300° C., at least about 1,400° C., at least about1,500° C., at least about 1,600° C., at least about 1,750° C., at leastabout 2,000° C., at least about 2,500° C., or at least about 3,000° C.In further embodiments, high temperature combustion can mean combustionat a temperature of about 1,200° C. to about 5,000° C., about 1,500° C.to about 4,000° C., about 1,600° C. to about 3,500° C., about 1,700° C.to about 3,200° C., about 1,800° C. to about 3,100° C., about 1,900° C.to about 3,000° C., or about 2,000° C. to about 3,000° C.

In certain embodiments, high temperature combustion according to theinvention may be carried out using a transpiration cooled combustor. Oneexample of a transpiration cooled combustor that may be used in theinvention is described in U.S. patent application Ser. No. 12/714,074,filed Feb. 26, 2010, the disclosure of which is incorporated herein byreference in its entirety. In some embodiments, a transpiration cooledcombustor useful according to the invention may include one or more heatexchange zones, one or more cooling fluids, and one or moretranspiration fluids.

The use of a transpiration cooled combustor according to the presentinvention is particularly advantageous over the known art around fuelcombustion for power production. For example, the use of transpirationcooling can be useful to prevent corrosion, fouling, and erosion in thecombustor. This further allows the combustor to work in a sufficientlyhigh temperature range to afford complete or at least substantiallycomplete combustion of the fuel that is used. These, and furtheradvantages, are further described herein.

In one particular aspect, a transpiration cooled combustor usefulaccording to the invention can include a combustion chamber at leastpartially defined by a transpiration member, wherein the transpirationmember is at least partially surrounded by a pressure containmentmember. The combustion chamber can have an inlet portion and an opposingoutlet portion. The inlet portion of the combustion chamber can beconfigured to receive the carbon containing fuel to be combusted withinthe combustion chamber at a combustion temperature to form a combustionproduct. The combustion chamber can be further configured to direct thecombustion product toward the outlet portion. The transpiration membercan be configured to direct a transpiration substance therethroughtoward the combustion chamber for buffering interaction between thecombustion product and the transpiration member. In addition, thetranspiration substance may be introduced into the combustion chamber toachieve a desired outlet temperature of the combustion product. Inparticular embodiments, the transpiration substance can at leastpartially comprise the circulating fluid.

The walls of the combustion chamber may be lined with a layer of porousmaterial through which is directed and flows the transpirationsubstance, such as CO₂ and/or H₂O.

In still further aspects, the inner transpiration member 2332 may extendfrom the inlet portion 222A to the outlet portion 222B of thetranspiration member 230. In some instances, the perforated/porousstructure of the inner transpiration member 2332 may extendsubstantially completely (axially) from the inlet portion 222A to theoutlet portion 222B such that the transpiration fluid 210 is directedinto substantially the entire length of the combustion chamber 222. Thatis, substantially the entirety of the inner transpiration member 2332may be configured with a perforated/porous structure such thatsubstantially the entire length of the combustion chamber 222 istranspiration-cooled. More particularly, in some aspects, the cumulativeperforation/pore area may be substantially equal to the surface area ofthe inner transpiration member 2332. In still other aspects, theperforations/pores may be spaced apart at an appropriate density suchthat substantially uniform distribution of the transpiration substancefrom the inner transpiration member 2332 into the combustion chamber 222is achieved (i.e., no “dead spots” where the flow or presence of thetranspiration substance 210 is lacking). In one example, a square inchof the inner transpiration member 2332 may include an array ofperforations/pores on the order of 250×250 per square inch, so as toprovide about 62,500 pores/in², with such perforations/pores beingspaced about 0.004 inches (about 0.1 mm) apart. The ratio of pore areato total wall area (% porosity) may be for example about 50%. The porearray may be varied over a wide range to adapt to other system designparameters, such as the desired pressure drop versus flow rate acrossthe transpiration member. Array sizes of about 10×10 to about10,000×10,000 per inch with porosity percentages of about 10% to about80% can utilized in some examples.

The flow of the transpiration substance through this poroustranspiration layer, and optionally through additional provisions, canbe configured to achieve a desired total exit fluid stream outlettemperature from the combustor. In some embodiments, as furtherdescribed herein, such temperature can be in the range of about 500° C.to about 2,000° C. This flow may also serve to cool the transpirationmember to a temperature below the maximum allowable operationaltemperature of the material forming the transpiration member. Thetranspiration substance may also serve to prevent impingement of anyliquid or solid ash materials or other contaminants in the fuel whichmight corrode, foul, or otherwise damage the walls. In such instances,it may be desirable to use a material for the transpiration member witha reasonable thermal conductivity so that incident radiant heat can beconducted radially outwards through the porous transpiration member andthen be intercepted by convective heat transfer from the surfaces of theporous layer structure to the fluid passing radially inwards through thetranspiration layer. Such a configuration may allow the subsequent partof the stream directed through the transpiration member to be heated toa temperature in a desirable range, such as about 500° C. to about1,000° C., while simultaneously maintaining the temperature of theporous transpiration member within the design range of the material usedtherefor. Suitable materials for the porous transpiration member mayinclude, for example, porous ceramics, refractory metal fiber mats,hole-drilled cylindrical sections, and/or sintered metal layers orsintered metal powders. A second function of the transpiration membermay be to ensure a substantially even radially inward flow oftranspiration fluid, as well as longitudinally along the combustor, toachieve good mixing between the transpiration fluid stream and thecombustion product while promoting an even axial flow of along thelength of the combustion chamber. A third function of the transpirationmember can be to achieve a velocity of diluent fluid radially inward soas to provide a buffer for or otherwise intercept solid and/or liquidparticles of ash or other contaminants within the combustion productsfrom impacting the surface of the transpiration layer and causingblockage or other damage. Such a factor may only be of importance, forexample, when combusting a fuel, such as coal, having a residual inertnon-combustible residue. The inner wall of the combustor pressure vesselsurrounding the transpiration member may also be insulated to isolatethe high temperature transpiration fluid stream within the combustor.

One embodiment of a combustor apparatus capable of use according to thepresent invention is schematically illustrated in FIG. 1, the combustorapparatus being generally indicated by the numeral 220. In this example,the combustor apparatus 220 may be configured to combust a particulatesolid such as coal to form a combustion product, though any othersuitable combustible carbon containing material, as disclosed herein,may also be used as a fuel. The combustion chamber 222 may be defined bya transpiration member 230, which is configured to direct atranspiration fluid therethrough into the combustion chamber 222 (i.e.,to facilitate transpiration cooling and/or to buffer interaction betweenthe combustion product and the transpiration member 230). One skilled inthe art will appreciate that the transpiration member 230 may besubstantially cylindrical, so as to define a substantially cylindricalcombustion chamber 222 having an inlet portion 222A and an opposingoutlet portion 222B. The transpiration member 230 may be at leastpartially surrounded by a pressure containment member 2338. The inletportion 222A of the combustion chamber 222 may be configured to receivea fuel mixture from a mixing arrangement, generally indicated by thenumeral 250. In other embodiments, such mixing arrangement may beabsent, and one or more of the materials input into the combustor may beseparately added via independent inlets. According to particularembodiments, the fuel mixture can be combusted within the combustionchamber 222 at a particular combustion temperature to form a combustionproduct, wherein the combustion chamber 222 is further configured todirect the combustion product toward the outlet portion 222B. A heatremoval device 2350 (see, e.g., FIG. 2) may be associated with thepressure containment member 2338 and configured to control a temperaturethereof. In particular instances, the heat removal device 2350 maycomprise a heat transfer jacket at least partially defined by a wall2336 opposing the pressure containment member 2338, wherein a liquid maybe circulated in water-circulating jackets 2337 defined therebetween. Inone embodiment, the circulated liquid may be water.

In one particular aspect, the porous inner transpiration member 2332 isthus configured to direct the transpiration fluid into the combustionchamber 222, such that the transpiration substance 210 enters thecombustion chamber 222 at a substantially right angle (90°) with respectto the inner surface of the inner transpiration member 2332. Among otheradvantages, the introduction of the transpiration substance 210 at thesubstantially right angle with respect to the inner transpiration member2332 may facilitate or otherwise enhance the effect of directing slagliquid or solid droplets or other contaminants or hot combustion fluidvortices away from the inner surface of the inner transpiration member2332. The lack of contact between the slag liquid or solid droplets mayprevent the coalescence of said droplets into large droplets or masses,which is known in the prior art to occur upon contact between dropletsor particles and solid walls. The introduction of the transpirationsubstance 210 at the substantially right angle with respect to the innertranspiration member 2332 may facilitate or otherwise enhance the effectof preventing the formation of combustion fluid vortices with sufficientvelocity perpendicular to and in proximity to the inner transpirationmember which may impinge on and damage the inner transpiration member.In such instances, the outer transpiration member 2331, the pressurecontainment member 2338, the heat transfer jacket 2336 and/or theinsulation layer 2339 may be configured, either individually or incombination, to provide a “manifold” effect (i.e., to provide asubstantially uniformly distributed supply) with regard to the deliveryof the transpiration substance/fluid 210 to and through the innertranspiration member 2332 and into the combustion chamber 222. That is,a substantially uniform supply (in terms of flow rate, pressure, or anyother suitable and appropriate measure) of the transpiration substance210 into the combustion chamber 222 may be achieved by configuring theouter transpiration member 2331, the pressure containment member 2338,the heat transfer jacket 2336 and/or the insulation layer 2339 toprovide a uniform supply of the transpiration substance 210 to the innertranspiration member 2332, or the supply of the transpiration substance210 about the outer surface of the inner transpiration member 2332 maybe particularly customized and configured such that a substantiallyuniform distribution of the transpiration substance 210 within thecombustion chamber 222 is achieved. Such substantially uniformdistribution may prevent the formation of hot combustion fluid vorticeswhich may otherwise form by interaction of non-uniform transpirationflow with the combustion fluid flow and which vertices may impinge onand damage the inner transpiration member.

The mixing arrangement 250 (when present) can be configured to mix acarbonaceous fuel 254 with enriched oxygen 242 and a circulating fluid236 to form a fuel mixture 200. The carbonaceous fuel 254 may beprovided in the form of a solid carbonaceous fuel, a liquid carbonaceousfuel, and/or a gaseous carbonaceous fuel. The enriched oxygen 242 may beoxygen having a molar purity of greater than about 85%. The enrichedoxygen 242 may be supplied, for example, by any air separationsystem/technique known in the art, such as, for example, a cryogenic airseparation process, or a high temperature ion transport membrane oxygenseparation process (from air), could be implemented. The circulatingfluid 236 may be carbon dioxide, as described herein. In instances wherethe carbonaceous fuel 254 is a particulate solid, such as powdered coal254A, the mixing arrangement 250 may be further configured to mix theparticulate solid carbonaceous fuel 254A with a fluidizing substance255. According to one aspect, the particulate solid carbonaceous fuel254A may have an average particle size of between about 50 microns andabout 200 microns. According to yet another aspect, the fluidizingsubstance 255 may comprise water and/or liquid CO₂ having a density ofbetween about 450 kg/m³ and about 1100 kg/m³. More particularly, thefluidizing substance 255 may cooperate with the particulate solidcarbonaceous fuel 254A to form a slurry 250A having, for example,between about 25 weight % and about 55 weight % of the particulate solidcarbonaceous fuel 254A. Though the oxygen 242 is shown in FIG. 1 asbeing mixed with the fuel 254 and the circulating fluid 236 prior tointroduction to the combustion chamber 222, one skilled in the art willappreciate that, in some instances, the oxygen 242 may be separatelyintroduced into the combustion chamber 222, as necessary or desired.

The mixing arrangement 250, in some aspects, may comprise, for example,an array of spaced apart injection nozzles (not shown) arranged about anend wall 223 of the transpiration member 230 associated with the inletportion 222A of the cylindrical combustion chamber 222. Injecting thefuel/fuel mixture into the combustion chamber 222 in this manner mayprovide, for example, a large surface area of the injected fuel mixtureinlet stream which may, in turn, facilitate rapid heat transfer to theinjected fuel mixture inlet stream by radiation. The temperature of theinjected fuel mixture may thus be rapidly increased to the ignitiontemperature of the fuel and may thus result in a compact combustion. Theinjection velocity of the fuel mixture may be in the range, for example,of between about 10 m/sec and about 40 m/sec, though these values maydepend on many factors, such as the configuration of the particularinjection nozzles. Such an injection arrangement may take many differentforms. For example, the injection arrangement may comprise an array ofholes, for instance, in the range of between about 0.5 mm and about 3 mmdiameter, wherein the fuel injected would be injected therethrough at avelocity of between about 10 m/s and about 40 m/s.

As more particularly shown in FIG. 2, the combustion chamber 222 can bedefined by the transpiration member 230, which may be at least partiallysurrounded by a pressure containment member 2338. In some instances, thepressure containment member 2338 may further be at least partiallysurrounded by a heat transfer jacket 2336, wherein the heat transferjacket 2336 can cooperate with the pressure containment member 2338 todefine one or more channels 2337 therebetween, through which a lowpressure water stream may be circulated. Through an evaporationmechanism, the circulated water may thus be used to control and/ormaintain a selected temperature of the pressure containment member 2338,for example, in a range of about 100° C. to about 250° C. In someaspects, an insulation layer 2339 may be disposed between thetranspiration member 230 and the pressure containment member 2338.

In some instances, the transpiration member 230 may comprise, forexample, an outer transpiration member 2331 and an inner transpirationmember 2332, the inner transpiration member 2332 being disposed oppositethe outer transpiration member 2331 from the pressure containment member2338, and defining the combustion chamber 222. The outer transpirationmember 2331 may be comprised of any suitable high temperature-resistantmaterial such as, for example, steel and steel alloys, includingstainless steel and nickel alloys. In some instances, the outertranspiration member 2331 may be configured to define firsttranspiration fluid supply passages 2333A extending therethrough fromthe surface thereof adjacent to the insulation layer 2339 to the surfacethereof adjacent to the inner transpiration member 2332. The firsttranspiration fluid supply passages 2333A may, in some instances,correspond to second transpiration fluid supply passages 2333B definedby the pressure containment member 2338, the heat transfer jacket 2336and/or the insulation layer 2339. The first and second transpirationfluid supply passages 2333A, 2333B may thus be configured to cooperateto direct a transpiration fluid therethrough to the inner transpirationmember 2332. In some instances, as shown, for example, in FIG. 1, thetranspiration fluid 210 may comprise the circulating fluid 236, and maybe obtained from the same source associated therewith. The first andsecond transpiration fluid supply passages 2333A, 2333B may beinsulated, as necessary, for delivering the transpiration fluid 210(i.e., CO₂) in sufficient supply and at a sufficient pressure such thatthe transpiration fluid 210 is directed through the inner transpirationmember 2332 and into the combustion chamber 222. Such measures involvingthe transpiration member 230 and associated transpiration fluid 210, asdisclosed herein, may allow the combustor apparatus 220 to operate atthe relatively high pressures and relatively high temperatures otherwisedisclosed herein.

In this regard, the inner transpiration member 2332 may be comprised of,for example, a porous ceramic material, a perforated material, alaminate material, a porous mat comprised of fibers randomly orientatedin two dimensions and ordered in the third dimension, or any othersuitable material or combinations thereof exhibiting the characteristicsrequired thereof as disclosed herein, namely multiple flow passages orpores or other suitable openings 2335 for receiving and directing thetranspiration fluid through the inner transpiration member 2332.Non-limiting examples of porous ceramic and other materials suitable forsuch transpiration-cooling systems include aluminum oxide, zirconiumoxide, transformation-toughened zirconium, copper, molybdenum, tungsten,copper-infiltrated tungsten, tungsten-coated molybdenum, tungsten-coatedcopper, various high temperature nickel alloys, and rhenium-sheathed orcoated materials. Sources of suitable materials include, for exampleCoorsTek, Inc., (Golden, Colo.) (zirconium); UltraMet Advanced MaterialsSolutions (Pacoima, Calif.) (refractory metal coatings); Orsam Sylvania(Danvers, Mass.) (tungsten/copper); and MarkeTech International, Inc.(Port Townsend, Wash.) (tungsten). Examples of perforated materialssuitable for such transpiration-cooling systems include all of the abovematerials and suppliers (where the perforated end structures may beobtained, for example, by perforating an initially nonporous structureusing methods known in the manufacturing art). Examples of suitablelaminate materials include all of the above materials and suppliers(where the laminate end structures may be obtained, for example, bylaminating nonporous or partially porous structures in such a manner asto achieve the desired end porosity using methods known in themanufacturing art).

FIGS. 3A and 3B illustrate that, in one aspect of a combustor apparatus220, the structure defining the combustion chamber 222 may be formedthrough a “hot” interference fit between the transpiration member 230and the surrounding structure, such as the pressure containment member2338 or the insulation layer 2339 disposed between the transpirationmember 230 and the pressure containment member 2338. For example, whenrelatively “cold,” the transpiration member 230 may be dimensioned to besmaller, radially and/or axially, with respect to the surroundingpressure containment member 2338. As such, when inserted into thepressure containment member 2338, a radial and/or axial gap may bepresent therebetween (see, e.g., FIG. 3A). Of course, such dimensionaldifferences may facilitate insertion of the transpiration member 230into the pressure containment member 2338. However, when heated, forexample, toward the operational temperature, the transpiration member230 may be configured to expand radially and/or axially to reduce oreliminate the noted gaps (see, e.g., FIG. 3B). In doing so, aninterference axial and/or radial fit may be formed between thetranspiration member 230 and the pressure containment member 2338. Ininstances involving a transpiration member 230 with an outertranspiration member 2331 and an inner transpiration member 2332, suchan interference fit may place the inner transpiration member 2332 undercompression. As such, suitable high temperature resistant brittlematerials, such as a porous ceramic, may be used to form the innertranspiration member 2332.

With the inner transpiration member 2332 thus configured, thetranspiration substance 210 may comprise, for example, carbon dioxide(i.e., from the same source as the circulating fluid 236) directedthrough the inner transpiration member 2332 such that the transpirationsubstance 210 forms a buffer layer 231 (i.e., a “vapor wall”)immediately adjacent to the inner transpiration member 2332 within thecombustion chamber 222, wherein the buffer layer 231 may be configuredto buffer interaction between the inner transpiration member 2332 andthe liquefied incombustible elements and heat associated with thecombustion product. That is, in some instances, the transpiration fluid210 can be delivered through the inner transpiration member 2332, forexample, at least at the pressure within the combustion chamber 222,wherein the flow rate of the transpiration fluid 210 (i.e., CO₂ stream)into the combustion chamber 222 is sufficient for the transpirationfluid 210 to mix with and cool the combustion products to form an exitfluid mixture at a sufficient temperature with respect to the inletrequirement of the subsequent downstream process (i.e., a turbine mayrequire an inlet temperature, for instance, of about 1,225° C.), butwherein the exit fluid mixture remains sufficiently high to maintainslag droplets or other contaminants in the fuel in a fluid or liquidstate. The liquid state of the incombustible elements of the fuel mayfacilitate, for example, separation of such contaminants from thecombustion product in liquid form, preferably in a free flowing, lowviscosity form, which will be less likely to clog or otherwise damageany removal system implemented for such separation. In practice, suchrequirements may depend on various factors such as the type of solidcarbonaceous fuel (i.e., coal) employed and the particularcharacteristics of the slag formed in the combustion process. That is,the combustion temperature within the combustion chamber 222 can be suchthat any incombustible elements in the carbonaceous fuel are liquefiedwithin the combustion product.

In particular aspects, the porous inner transpiration member 2332 isthus configured to direct the transpiration fluid and into thecombustion chamber 222 in a radially inward manner so as to form a fluidbarrier wall or buffer layer 231 about the surface of the innertranspiration member 2332 defining the combustion chamber 222 (see,e.g., FIG. 2). The surface of the inner transpiration member 2332 isalso heated by combustion product. As such, the porous innertranspiration member 2332 may be configured to have a suitable thermalconductivity such that the transpiration fluid 210 passing through theinner transpiration member 2332 is heated, while the porous innertranspiration member 2332 is simultaneously cooled, resulting in thetemperature of the surface of the inner transpiration member 2332defining the combustion chamber 222 being, for example, about 1,000° C.in the region of the highest combustion temperature. The fluid barrierwall or buffer layer 231 formed by the transpiration fluid 210 incooperation with the inner transpiration member 2332 thus buffersinteraction between the inner transpiration member 2332 and the hightemperature combustion products and the slag or other contaminantparticles and, as such, buffers the inner transpiration member 2332 fromcontact, fouling, or other damage. Further, the transpiration fluid 210may be introduced into the combustion chamber 222 via the innertranspiration member 2332 in such a manner so as to regulate an exitmixture of the transpiration fluid 210 and the combustion product aboutthe outlet portion 222B of the combustion chamber 222 at a desiredtemperature (e.g., about 500° C. to about 2,000° C.).

In specific embodiments, the combustor apparatus 220 thus may beconfigured as a high efficiency, transpiration-cooled combustorapparatus capable of providing relatively complete combustion of a fuel254 at a relatively high operating temperature as described herein. Sucha combustor apparatus 220 may, in some instances, implement one or morecooling fluids, and/or one or more transpiration fluids 210. Inassociation with the combustor apparatus 220, additional components mayalso be implemented. For example, an air separation unit may be providedfor separating N₂ and O₂, and a fuel injector device may be provided forreceiving O₂ from the air separation unit and combining the O₂ with aCO₂ circulating fluid, and a fuel stream comprising a gas, a liquid, asupercritical fluid, or a solid particulate fuel slurried in a highdensity CO₂ fluid.

In another aspect, the transpiration-cooled combustor apparatus 220 mayinclude a fuel injector for injecting a pressurized fuel stream into thecombustion chamber 222 of the combustor apparatus 220, wherein the fuelstream may comprise a processed carbonaceous fuel 254, a fluidizingmedium 255 (which may comprise the circulating fluid 236, as discussedherein), and oxygen 242. The oxygen (enriched) 242 and the CO₂circulating fluid 236 can be combined as a homogeneous supercriticalmixture. The quantity of oxygen present may be sufficient to combust thefuel and produce combustion products having a desired composition. Thecombustor apparatus 220 may also include a combustion chamber 222,configured as a high pressure, high temperature combustion volume, forreceiving the fuel stream, as well as a transpiration fluid 210 enteringthe combustion volume through the walls of a porous transpiration member230 defining the combustion chamber 222. The feed rate of thetranspiration fluid 210 may be used to control the combustor apparatusoutlet portion/turbine inlet portion temperature to a desired valueand/or to cool the transpiration member 230 to a temperature compatiblewith the material forming the transpiration member 230. Thetranspiration fluid 210 directed through the transpiration member 230provides a fluid/buffer layer at the surface of the transpiration member230 defining the combustion chamber 222, wherein the fluid/buffer layermay prevent particles of ash or liquid slag resulting from certain fuelcombustion from interacting with the exposed walls of the transpirationmember 230.

The combustion chamber 222 may further be configured such that the fuelstream (and the circulating fluid 236) can be injected or otherwiseintroduced into the combustion chamber 222 at a pressure greater thanthe pressure at which combustion occurs. The combustor apparatus 220 mayinclude a pressure containment member 2338 at least partiallysurrounding the transpiration member 230 defining the combustion chamber230, wherein an insulating member 2339 can be disposed between thepressure containment member 2338 and the transpiration member 230. Insome instances, a heat removal device 2350, such as a jacketed watercooling system defining water-circulating jackets 2337, may be engagedwith the pressure containment member 2338 (i.e., externally to thepressure containment member 2338 forming the “shell” of the combustorapparatus 220). The transpiration fluid 210 implemented in connectionwith the transpiration member 230 of the combustor apparatus 220 can be,for example, CO₂ mixed with minor quantities of H₂O and/or an inert gas,such as N₂ or argon. The transpiration member 230 may comprise, forexample, a porous metal, a ceramic, a composite matrix, a layeredmanifold, any other suitable structure, or combinations thereof. In someaspects, the combustion within the combustion chamber 222 can produce ahigh pressure, high temperature combustion product stream, which may besubsequently directed to a power-producing apparatus, such as a turbine,for expansion in relation thereto, as more fully described herein.

The relatively high pressures implemented by embodiments of a combustorapparatus as disclosed herein, may function to concentrate the energyproduced thereby to a relatively high intensity in a minimal volume,essentially resulting in a relatively high energy density. Therelatively high energy density allows downstream processing of thisenergy to be performed in a more efficient manner than at lowerpressures, and thus provides a viability factor for the technology.Aspects of the present disclosure may thus provide an energy density atorders of magnitude greater than existing power plants (i.e., by 10-100fold). The higher energy density increases the efficiency of theprocess, but also reduces the cost of the equipment needed to implementthe energy transformation from thermal energy to electricity, byreducing the size and mass of the equipment, thus the cost of theequipment.

As otherwise discussed herein, the combustor apparatus used in theinventive methods and systems can be useful for combustion of a varietyof different carbon containing fuel sources. In specific embodiments,the carbon containing fuel can be substantially completely combustedsuch that no liquid or solid incombustible materials are included in thecombustion product stream. In some embodiments, however, a solid carboncontaining fuel (e.g., coal) that may be used in the invention mayresult in the presence of incombustible materials. In specificembodiments, the combustor apparatus may include the capability ofachieving a combustion temperature which causes the incombustibleelements in the solid carbon containing fuel to be liquefied during thecombustion process. In such instances, provisions for removing theliquefied incombustible elements may be applied. Removal may beaccomplished, for example, using cyclone separators, impingementseparators, or beds of graded refractory granular filters arranged in anannular configuration, or combinations thereof. In particularembodiments, the droplets may be removed from the high temperaturecirculating fluid stream by a series of cyclone separators such as, forexample, a separator apparatus 2340 as shown in FIG. 4. Generally,aspects of such a cyclonic separator implemented by the presentdisclosure may comprise a plurality of serially-arranged centrifugalseparator devices 100, including an inlet centrifugal separator device100A configured to receive the combustion product/exit fluid stream andthe liquefied incombustible elements associated therewith, and an outletcentrifugal separator device 100B configured to exhaust the combustionproduct/exit fluid stream having the liquefied incombustible elementssubstantially removed therefrom. Each centrifugal separator device 100includes a plurality of centrifugal separator elements or cyclones 1operably arranged in parallel about a central collector pipe 2, whereineach centrifugal separation element, or cyclone 1, is configured toremove at least a portion of the liquefied incombustible elements fromthe combustion product/exit fluid stream, and to direct the removedportion of the liquefied incombustible elements to a sump 20. Such aseparator apparatus 2340 may be configured to operate at an elevatedpressure and, as such, may further comprise a pressure-containinghousing 125 configured to house the centrifugal separator devices andthe sump. According to such aspects, the pressure-containing housing 125may be an extension of the pressure containment member 2338 alsosurrounding the combustor apparatus 220, or the pressure-containinghousing 125 may be a separate member capable of engaging the pressurecontainment member 2338 associated with the combustor apparatus 220. Ineither instance, due to the elevated temperature experienced by theseparator apparatus 2340 via the exit fluid stream, thepressure-containing housing 125 may also include a heat-dispersionsystem, such as a heat transfer jacket having a liquid circulatedtherein (not shown), operably engaged therewith for removing heattherefrom. In some aspects, a heat recovery device (not shown) may beoperably engaged with the heat transfer jacket, wherein the heatrecovery device may be configured to receive the liquid circulated inthe heat transfer jacket and to recover thermal energy from that liquid.

In particular embodiments, the (slag removal) separator apparatus 2340,shown in FIG. 4, can be configured to be serially disposed with thecombustor apparatus 220 about the outlet portion 222B thereof forreceiving the exit fluid stream/combustion products therefrom. Thetranspiration-cooled exit fluid stream from the combustor apparatus 220,with the liquid slag (incombustible elements) droplets therein, can bedirected to enter a central collector provision 2A of the inletcentrifugal separator device 100A via a conical reducer 10. In oneaspect, the separator apparatus 2340 may include three centrifugalseparator devices 100A, 100B, 100C (though one skilled in the art willappreciate that such a separator apparatus may include one, two, three,or more centrifugal separator devices, as necessary or desired). In thisinstance, the three centrifugal separator devices 100A, 100B, 100Coperably arranged in series provides a 3 stage cyclonic separation unit.Each centrifugal separator device includes, for example, a plurality ofcentrifugal separator elements (cyclones 1) arranged about thecircumference of the corresponding central collector pipe 2. The centralcollector provisions 2A and the central collector pipes 2 of the inletcentrifugal separator device 100A, and the medial centrifugal separatordevice 100C are each sealed at the outlet end thereof. In thoseinstances, the exit fluid stream is directed into branch channels 11corresponding to each of the centrifugal separator elements (cyclones 1)of the respective centrifugal separator device 100. The branch channels11 are configured to engage the inlet end of the respective cyclone 1 toform a tangential inlet therefor (which causes, for instance, the exitfluid stream entering the cyclone 1 to interact with the wall of thecyclone 1 in a spiral flow). The outlet channel 3 from each cyclone 1 isthen routed into the inlet portion of the central collector pipe 2 ofthe respective centrifugal separator device 100. At the outletcentrifugal separator device 100B, the exit fluid stream (having theincombustible elements substantially separated therefrom) is directedfrom the central collector pipe of the outlet centrifugal separatordevice 100B and via a collector pipe 12 and an outlet nozzle 5, suchthat the “clean” exit fluid stream can then be directed to a subsequentprocess, such as that associated with the transformation apparatus. Theexemplary three stage cyclonic separation arrangement thus allowsremoval of slag down to, for example, below 5 ppm by mass in the exitfluid stream.

At each stage of the separator apparatus 2340, the separated liquid slagis directed from each of the cyclones 1 via outlet tubes 4 which extendtoward a sump 20. The separated liquid slag is then directed into anoutlet nozzle or pipe 14 extending from the sump 20 and thepressure-containing housing 125 for removal and/or recovery ofcomponents therefrom. In accomplishing the removal of the slag, theliquid slag may be directed though a water-cooled section 6 or otherwisethrough a section having a high pressure, cold water connection, whereininteraction with the water causes the liquid slag to solidify and/orgranulate. The mixture of solidified slag and water may then beseparated in a vessel (collection provision) 7 into a slag/water fluidmixture which can be removed, particularly following pressure reduction,through a suitable valve 9, while any residual gas may be removed via aseparate line 8. A pair of vessels with associated systems operating insequence can allow for continuous operation of the system in someembodiments.

Since the separator apparatus 2340 can be implemented in conjunctionwith the relatively high temperature combustion product stream (i.e., ata temperature sufficient to maintain the incombustible elements inliquid form with a relatively low viscosity), it may be desirable, insome instances, that surfaces of the separator apparatus 2340 exposed toone of the combustion product/exit fluid stream and the liquefiedincombustible elements associated therewith be comprised of a materialconfigured to have at least one of a high temperature resistance, a highcorrosion resistance, and a low thermal conductivity. Examples of suchmaterials may include zirconium oxide and aluminum oxide, though suchexamples are not intended to be limiting in any manner. As such, incertain aspects, the separator apparatus 2340 can be configured tosubstantially remove the liquefied incombustible elements from thecombustion product/exit fluid stream and to maintain the incombustibleelements in a low viscosity liquid form at least until removal thereoffrom the sump 20. Of course, in embodiments where a non-solid fuel isused and incombustible materials are not included in the combustionproduct stream, the addition of the slag separator can be unnecessary.

In some embodiments, the separator apparatus 2340 may be used toseparate particulate solid ash residue from the combustion of any fuelwhich produces an incombustible solid residue, such as coal. Forexample, the coal could be ground to a desired size (e.g., a size suchthat less than 1% by weight of the particulate or powdered coalcomprises particles greater than 100 μm in size) and slurried withliquid CO₂. In specific embodiments, the liquid CO₂ could be at atemperature of about −40° C. to about −18° C. The slurry may compriseabout 40% to about 60% by weight of coal. The slurry then can bepressurized to the required combustion pressure. Referring to FIG. 1,the recycle stream 236 could be split in relation to the mode of entryinto the combustor 220. A first portion (stream 236 a) could be input tothe combustor 220 via the mixing arrangement 250, and a second portion(stream 236 b) could be input to the combustor 220 by being passedthrough the transpiration cooling layer 230. As described above it ispossible to operate the burner 220 with a ratio of O₂ to fuel whichresults in the formation of a reducing gas mixture (e.g., comprising H₂,CH₄, CO, H₂S, and/or NH₃). The portion of stream 236 entering thecombustor through the transpiration cooling layer 230 can be used tocool the mixture of the combustion gases and the CO₂ circulating fluidto a temperature substantially below the ash solidification temperature(e.g., in the range of about 500° C. to about 900° C. The total gasstream 5 from the separator apparatus 2340 can be passed through afiltration unit, which reduces the residual solid ash particulate levelto a very low value (e.g., below about 2 mg/m³ of gas passing throughthe filter). This cleaned gas can then be combusted in a secondcombustor where it can be diluted with a further portion of the recyclefluid stream 236. In such embodiments, the recycle fluid stream 236could be apportioned between the two combustors, as necessary.

Any carbon containing material may be used as a fuel according to thepresent invention. In particular, because of the high pressures and hightemperatures maintained by the oxygen-fueled combustor apparatus used inthe inventive methods and systems, useful fuels include, but are notlimited to, various grades and types of coal, wood, oil, fuel oil,natural gas, coal-based fuel gas, tar from tar sands, bitumen, biomass,algae, graded combustible solid waste refuse, asphalt, used tires,diesel, gasoline, jet fuel (JP-5, JP-4), gases derived from thegasification or pyrolysis of hydro-carbonaceous material, ethanol, solidand liquid biofuels. This may be considered an important departure fromprior art systems and methods. For example, known art systems forcombustion of solid fuels, such as coal, require considerably differentdesigns than systems for combustion of non-solid fuels, such as naturalgas.

The fuels can be suitably processed to allow for injection into thecombustion apparatus at sufficient rates and at pressures above thepressure within the combustion chamber. Such fuels may be in liquid,slurry, gel, or paste form with appropriate fluidity and viscosity atambient temperatures or at elevated temperatures. For example, the fuelmay be provided at a temperature of about 30° C. to about 500° C., about40° C. to about 450° C., about 50° C. to about 425° C., or about 75° C.to about 400° C. Any solid fuel materials may be ground or shredded orotherwise processed to reduce particles sizes, as appropriate. Afluidization or slurrying medium can be added, as necessary, to achievea suitable form and to meet flow requirements for high pressure pumping.Of course, a fluidization medium may not be needed depending upon theform of the fuel (i.e., liquid or gas). Likewise, the circulatedcirculating fluid may be used as the fluidization medium, in someembodiments.

Transpiration fluids suitable in a combustor useful according to theinvention can include any fluid capable of flowing in sufficientquantity and pressure through the inner liner to form the vapor wall. Inthe present embodiment, CO₂ can be an ideal transpiration fluid in thatthe vapor wall formed has good thermal insulating properties as well asvisible and UV light absorption properties. CO₂ can be used as asupercritical fluid. Other examples of transpiration fluid include H₂O,cooled combustion product gases recycled from downstream, oxygen,hydrogen, natural gas, methane, and other light hydrocarbons. Fuels mayespecially be used as transpiration fluids during startup of thecombustor to achieve appropriate operating temperatures and pressures inthe combustor prior to injection of the main fuel source. Fuels may alsobe used as transpiration fluids to adjust the operating temperature andpressure of the combustor during switchover between main fuel sources,such as when switching from coal to biomass as the primary fuel. In someembodiments, two or more transpiration fluids can be used. Further,different transpiration fluids can be used in different positions alongthe combustor. For example, a first transpiration fluid can be used in ahigh temperature heat exchange zone and a second transpiration fluid canbe used in a lower temperature heat exchange zone. The transpirationfluid can be optimized for the temperature and pressure conditions ofthe combustion chamber where the transpiration fluid forms the vaporwall. In the present example the transpiration fluid is preheatedrecycle CO₂.

In one aspect, the present invention provides methods of powergeneration. Specifically, the methods make use of a CO₂ circulatingfluid that is preferably recycled through the method, as describedherein. The inventive methods also make use of high efficiencycombustors, such as a transpiration cooled combustor, as describedabove. In certain embodiments, the methods generally can be described inrelation to the flow diagram shown in FIG. 5. As seen therein, acombustor 220 is provided, and various inputs are provided therein. Acarbon containing fuel 254 and O₂ 242 (as necessary) can be introducedinto the combustor 220 along with a circulating fluid 236 (CO₂ in thepresent embodiment). A mixing arrangement 250 illustrated by a dashedline indicates that this component is optionally present. Specifically,any combination of two or all three materials (fuel, O₂, and CO₂circulating fluid) may be combined in the mixing arrangement 250 priorto introduction into the combustor 220.

In various embodiments, it can be desirable for the materials enteringthe combustor to exhibit specific physical characteristics that canfacilitate desirable, efficient operation of the power generationmethod. For example, in certain embodiments, it can be desirable for theCO₂ in the CO₂ circulating fluid to be introduced into the combustor ata defined pressure and/or temperature. Specifically, it can bebeneficial for the CO₂ introduced into the combustor to have a pressureof at least about 8 MPa. In further embodiments, the CO₂ introduced intothe combustor can be at a pressure of at least about 10 MPa, at leastabout 12 MPa, at least about 14 MPa, at least about 15 MPa, at leastabout 16 MPa, at least about 18 MPa, at least about 20 MPa, at leastabout 22 MPa, at least about 24 MPa, or at least about 25 MPa. In otherembodiments, the pressure can be about 8 MPa to about 50 MPa, about 12MPa to about 50 MPa, about 15 MPa to about 50 MPa, about 20 MPa to about50 MPa, about 22 MPa to about 50 MPa, about 22 MPa to about 45 MPa,about 22 MPa to about 40 MPa, about 25 MPa to about 40 MPa, or about 25MPa to about 35 MPa. Further, it can be beneficial for the CO₂introduced into the combustor to have a temperature of at least about200° C. In further embodiments, the CO₂ introduced into the combustorcan be at a temperature of at least about 250° C., at least about 300°C., at least about 350° C., at least about 400° C., at least about 450°C., at least about 500° C., at least about 550° C., at least about 600°C., at least about 650° C., at least about 700° C., at least about 750°C., at least about 800° C., at least about 850° C., or at least about900° C.

In some embodiments, it can be desirable for the fuel introduced intothe combustor to be provided under specific conditions. For example, incertain embodiments, it can be desirable for the carbon containing fuelto be introduced into the combustor at a defined pressure and/ortemperature. In some embodiments, the carbon containing fuel can beintroduced into the combustor under conditions that are identical orsubstantially similar to the conditions of the CO₂ circulating fluid.The phrase “substantially similar conditions” can mean a conditionparameter that is within 5%, within 4%, within 3%, within 2%, or within1% of the referenced condition parameter described herein (e.g., thecondition parameter for the CO₂ circulating fluid). In certainembodiments, the carbon containing fuel may be mixed with the CO₂circulating fluid prior to introduction into the combustor. In suchembodiments, it would be expected that the carbon containing fuel andthe CO₂ circulating fluid would be under identical or substantiallysimilar conditions (which specifically may encompass the conditionsdescribed in relation to the CO₂ circulating fluid). In otherembodiments, the carbon containing fuel may be introduced to thecombustor separately from the CO₂ circulating fluid. In such cases, thecarbon containing fuel still may be introduced at a pressure asdescribed in relation to the CO₂ circulating fluid. In some embodiments,it may be useful to maintain the carbon containing fuel at a temperaturethat is different than the temperature of the CO₂ circulating fluidprior to introduction to the combustor. For example, the carboncontaining fuel could be introduced to the combustor at a temperature ofabout 30° C. to about 800° C., about 35° C. to about 700° C., about 40°C. to about 600° C., about 45° C. to about 500° C., about 50° C. toabout 400° C., about 55° C. to about 300° C., about 60° C. to about 200°C., about 65° C. to about 175° C., or about 70° C. to about 150° C.

In other embodiments, it can be desirable for the O₂ introduced into thecombustor to be provided under specific conditions. Such conditions maybe incident to the method of providing the O₂. For example, it can bedesirable to provide the O₂ at a specific pressure. Specifically, it canbe beneficial for the O₂ introduced into the combustor to have apressure of at least about 8 MPa. In further embodiments, the O₂introduced into the combustor can be at a pressure of at least about 10MPa, at least about 12 MPa, at least about 14 MPa, at least about 15MPa, at least about 16 MPa, at least about 18 MPa, at least about 20MPa, at least about 22 MPa, at least about 24 MPa, at least about 25MPa, at least about 30 MPa, at least about 35 MPa, at least about 40MPa, at least about 45 MPa, or at least about 50 MPa. Provision of theO₂ can encompass the use of an air separator (or oxygen separator), suchas a cryogenic O₂ concentrator, an O₂ transport separator, or anysimilar apparatus such as an O₂ ion transport separator for separatingO₂ from ambient air. Separately, or in combination therewith, theprovision of the O₂ can include pressurizing the O₂ to achieve thedesired pressure, as described above. Such action can cause heating ofthe O₂. In some embodiments, it may be desirable for the O₂ to be at adesired temperature that is different from the temperature achievedinherently by pressurizing the gas. For example, it may be desirable forthe O₂ to be provided to the combustor at a temperature of 30° C. toabout 900° C., about 35° C. to about 800° C., about 40° C. to about 700°C., about 45° C. to about 600° C., about 50° C. to about 500° C., about55° C. to about 400° C., about 60° C. to about 300° C., about 65° C. toabout 250° C., or about 70° C. to about 200° C. Moreover, in someembodiments, the O₂ can be introduced into the combustor underconditions that are identical or substantially similar to the conditionsof the CO₂ circulating fluid and/or the carbon containing fuel. This mayarise from mixing of the various components prior to introduction intothe combustor or may arise from specific methods of preparing the O₂ forintroduction into the combustor. In particular embodiments, the O₂ maybe combined with an amount of CO₂ in a defined molar proportion so thatthe O₂ may be provided at the same temperature as the CO₂ circulatingfluid stream. For example, the combination could be carried out at atemperature below 100° C. while the CO₂ is at a supercritical pressure.This eliminates danger of combustion associated with heating pure O₂alone due to the diluting effect of the CO₂. Such mixture could be at aCO₂/O₂ ratio of about 1:2 to about 5:1, about 1:1 to about 4:1, or about1:1 to about 3:1.

In some embodiments, it can be useful for the O₂ supplied to thecombustor to be substantially purified (i.e., upgraded in terms of themolar content of O₂ in relation to other components naturally present inair). In certain embodiments, the O₂ can have a purity of greater thanabout 50% molar, greater than about 60% molar, greater than about 70%molar, greater than about 80% molar, greater than about 85% molar,greater than about 90% molar, greater than about 95% molar, greater thanabout 96% molar, greater than about 97% molar, greater than about 98%molar, greater than about 99% molar, or greater than about 99.5% molar.In other embodiments, the O₂ can have a molar purity of about 85% toabout 99.6% molar, about 85% to about 99% molar, about 90% to about 99%molar, about 90% to about 98% molar, or about 90% to about 97% molar.Overall CO₂ recovery from the carbon in the fuel favors the use ofhigher purities in the range of at least about 99.5% molar.

The CO₂ circulating fluid can be introduced to the combustor at theinlet of the combustor along with the O₂ and the carbon containing fuel.As described above in relation to a transpiration cooled combustor,however, the CO₂ circulating fluid also can be introduced to thetranspiration cooled combustor as all or part of the transpirationcooling fluid directed into the transpiration member through one or moretranspiration fluid supply passages formed in the transpiration cooledcombustor. In some embodiments according to the invention, the CO₂circulating fluid can be introduced into the combustor at the inlet ofthe combustor (i.e., along with the O₂ and the fuel), and the CO₂circulating fluid also can be introduced into the combustor through thetranspiration member as all or part of the transpiration cooling fluid.In other embodiments, the CO₂ circulating fluid can be introduced intothe combustor only through the transpiration member as all or part ofthe transpiration cooling fluid (i.e., no CO₂ being introduced into thecombustor inlet with the O₂ and the fuel).

In some embodiments, the invention may be characterized in relation tothe ratio of the various components introduced into the combustionchamber. In order to achieve maximum efficiency of combustion it can beuseful to combust the carbon containing fuel at a high temperature. Thetemperature of combustion and the temperature of the combustion productstream leaving the combustor, however, may need to be controlled withindefined parameters. To this end, it can be useful to provide the CO₂circulating fluid at a specific ratio to the fuel so that combustiontemperature and/or the turbine inlet temperature can be controlledwithin the desired range while also maximizing the amount of energy thatcan be converted to power. In specific embodiments, this can be achievedby adjusting the ratio of the CO₂ circulating fluid stream to the carbonin the fuel. The desired ratio can be influenced by the desired turbineinlet temperature as well as the temperature difference between theinlet and outlet streams at the hot end of the heat exchanger, as ismore fully described herein. The ratio specifically can be described asthe molar ratio of the CO₂ in the CO₂ circulating fluid to the carbonpresent in the carbon containing fuel. For determining the molar amountof CO₂ introduced into the combustor, in some embodiments, the entirecontent of CO₂ provided to the combustor (i.e., introduced at the inletwith the fuel and the O₂, as well as any CO₂ used as a transpirationcooling fluid) is included in the calculation. In specific embodiments,however, the calculation may be based solely on the molar amount of CO₂introduced at the combustor inlet (i.e., excluding any CO₂ used as atranspiration cooling fluid). In embodiments wherein the CO₂ isintroduced into the combustor only as a transpiration cooling fluid, thecalculation is based upon the content of CO₂ introduced into thecombustor as the transpiration cooling fluid. Thus, the ratio may bedescribed as the molar content of CO₂ input to the combustor inlet inrelation to the carbon in the fuel input to the combustor. Alternately,the ratio may be described as the molar content of CO₂ input to thecombustor through the transpiration cooling fluid in relation to thecarbon in the fuel input to the combustor.

In certain embodiments, the ratio of CO₂ circulating fluid to carbon inthe fuel introduced into the combustor, on a molar basis, can be about10 to about 50 (i.e., about 10 moles of CO₂ per 1 mole of carbon in thefuel to about 50 moles of CO₂ per 1 mole of carbon in the fuel). Infurther embodiments, the ratio of CO₂ in the circulating fluid to carbonin the fuel can be about 15 to about 50, about 20 to about 50, about 25to about 50, about 30 to about 50, about 15 to about 45, about 20 toabout 45, about 25 to about 45, about 30 to about 45, about 15 to about40, about 20 to about 40, about 25 to about 40, or about 30 to about 40.In other embodiments, the ratio of CO₂ in the circulating fluid tocarbon in the fuel can be at least about 5, at least about 10, at leastabout 15, at least about 20, at least about 25, or at least about 30.

The molar ratio of CO₂ introduced into the combustor to carbon presentin the carbon containing fuel can have an important impact on overallsystem thermal efficiency. This impact on efficiency also may beimpacted by the design and function of further components of the system,including the heat exchanger, the water separator, and thepressurization unit. The combination of the various elements of thesystem and method described herein leads to the ability to achieve highthermal efficiency at the specific CO₂/C ratios described herein.Previously known systems and methods that do not include the variouselements described herein typically would require a CO₂/C molar ratiothat is significantly lower than used in the present invention toachieve efficiencies approaching those achieved herein. The presentinvention, however, has identified highly effective systems and methodsfor recycling CO₂ that enables the use of CO₂/C molar ratios thatgreatly exceed those that can be used in the known art. The use of highCO₂/C molar ratios according to the present invention further isadvantageous for diluting impurities in the combustion stream. Thecorrosive or erosive effects of impurities (e.g., chlorides and sulfur)on system components are thus greatly diminished. High chloride and/orhigh sulfur coal presently cannot be used in known systems because thecombustion products from such coal (which includes HCl and H₂SO₄) aretoo corrosive and erosive for the power plant components to withstand.Many other impurities (e.g., solid ash particles and volatile materialscontaining elements such as lead, iodine, antimony, and mercury) alsocan cause sever internal damage to power plant components at hightemperatures. The dilutive effect of the recycled CO₂ can greatlyameliorate or eliminate the deleterious effects of such impurities onpower plant components. The selection of CO₂/C molar ratios then caninvolve a complex consideration of effects on efficiency and plantcomponent erosion and corrosion and of the design of the CO₂ recyclesystem components and function. The present invention enables the highlyefficient recycle of CO₂ and thus the increased CO₂/C molar ratios witha high thermal efficiency that could not have been predicted by theknown art. The high CO₂/C molar ratios thus convey at least theaforementioned advantages.

Similarly, it can be useful to control the content of O₂ introduced intothe combustor. This particularly can depend upon the nature of theoperation of the combustor. As more fully described herein, the methodsand systems of the invention can allow for operation in a fullyoxidizing mode, a fully reducing mode, or variations of both. In a fullyoxidizing mode, the amount of O₂ provided to the combustor preferablywould be at least a stoichiometric amount necessary to achieve completeoxidization of the carbon containing fuel. In certain embodiments, theamount of O₂ provided would be in excess of the noted stoichiometricamount by at least about 0.1% molar, at least about 0.25% molar, atleast about 0.5% molar, at least about 1% molar, at least about 2%molar, at least about 3% molar, at least about 4% molar, or at leastabout 5% molar. In other embodiments, the amount of O₂ provided would bein excess of the noted stoichiometric amount by about 0.1% to about 5%molar, about 0.25% to about 4% molar, or about 0.5% to about 3% molar.In a fully reducing mode, the amount of O₂ provided to the combustorpreferably would be a stoichiometric amount necessary to convert thecarbon containing fuel to the components H₂, CO, CH₄, H₂S, and NH₃ plusan excess of at least about 0.1% molar, at least about 0.25% molar, atleast about 0.5% molar, at least about 1% molar, at least about 2%molar, at least about 3% molar, at least about 4% molar, or at leastabout 5% molar. In other embodiments, the amount of O₂ provided would bein excess of the noted stoichiometric amount by about 0.1% to about 5%molar, about 0.25% to about 4% molar, or about 0.5% to about 3% molar.

The methods of the invention can, in some embodiments, be characterizedin relation to the physical state of the CO₂ throughout the varioussteps in the process. CO₂ is recognized as existing in various statesdepending upon the physical conditions of the material. CO₂ has a triplepoint at 0.518 MPa and −56.6° C., but CO₂ also has a critical pressureand temperature of 7.38 MPa and 31.1° C. Beyond this critical point, CO₂exists as a supercritical fluid, and the present invention has realizedthe ability to maximize power generation efficiency by keeping the CO₂in a specified state at specific points in the cycle. In specificembodiments, the CO₂ introduced into the combustor is preferably in theform of a supercritical fluid.

Efficiency of a power generating system or method typically isunderstood to describe the ratio of energy output by the system ormethod to energy input into the system or method. In the case of a powerproduction system or method, efficiency often is described as the ratioof electricity or power (e.g., in megawatts or Mw) output to thecustomer grid to the total lower heating value thermal energy of thefuel combusted to generate the electricity (or power). This ratio thenmay be referred to as the net system or method efficiency (on an LHVbasis). This efficiency can take into account all of the energy requiredfor internal system or method processes, including production ofpurified oxygen (e.g., via an air separation unit), pressurization ofCO₂ for transport to a pressurized pipeline, and other system or methodconditions requiring energy input.

In various embodiments, the systems and methods of the present inventioncan make use of predominantly CO₂ as a working fluid in a cycle in whicha carbon containing fuel is combusted (i.e., in a combustor) insubstantially pure O₂ at a pressure in excess of the critical pressureof CO₂ to produce a combustion product stream. This stream is expandedacross a turbine and is then passed through a recuperator heatexchanger. In the heat exchanger, the turbine exhaust preheats a recycleCO₂ circulating fluid in a supercritical state. This preheated, recycledCO₂ circulating fluid is input into the combustor where it mixes withthe products from combustion of the carbon containing fuel to give atotal flow at a defined maximum turbine inlet temperature. The inventioncan provide excellent efficiency at least in part because of therecognition of the benefits of minimizing the temperature difference atthe hot end of the recuperator heat exchanger. This minimization can beachieved by using a low temperature level heat source to heat a portionof the recycle CO₂ prior to introduction to the combustor. At theselower temperature levels, the specific heat and density of thesupercritical CO₂ is very high, and this extra heating can allow theturbine exhaust flow to preheat the CO₂ to a much higher temperature,and this can significantly reduce the temperature difference at the hotend of the recuperator heat exchanger. Useful low temperature heatsources in specific embodiments are the air compressors used in thecryogenic air separation plant operated adiabatically or the hot exhaustflow from a conventional gas turbine. In specific embodiments of thepresent invention, the temperature difference at the hot end of therecuperator heat exchanger is less than about 50° C., and preferably inthe range of about 10° C. to about 30° C. The use of a low pressureratio (e.g., below about 12) is a further factor which can increaseefficiency. The use of CO₂ as a working fluid coupled with the lowpressure ratio reduces the energy loss in raising the pressure of thecooled turbine exhaust to the recycle pressure. A further advantage isthe ability to produce the quantity of carbon in the fuel converted toCO₂ as a high pressure fluid above the supercritical pressure of CO₂ atpipeline pressure (typically about 10 MPa to about 20 MPa) with verylittle additional parasitic power consumption at near 100% carboncapture from the fuel. Such system and method parameters are furtherdescribed herein in even greater detail.

Returning to FIG. 5, the carbon containing fuel 254 introduced to thecombustor 220 along with the O₂ 242 and the CO₂ circulating fluid 236 iscombusted to provide a combustion product stream 40. In specificembodiments, the combustor 220 is a transpiration cooled combustor, suchas described above. Combustion temperature can vary depending upon thespecific process parameters—e.g., the type of carbon containing fuelused, the molar ratio of CO₂ to carbon in the fuel as introduced intothe combustor, and/or the molar ratio of CO₂ to O₂ introduced into thecombustor. In specific embodiments, the combustion temperature is atemperature as described above in relation to the description of thetranspiration cooled combustor. In particularly preferred embodiments,combustion temperatures in excess of about 1,300° C., as describedherein, may be advantageous.

It also can be useful to control combustion temperature such that thecombustion product stream leaving the combustor has a desiredtemperature. For example, it can be useful for the combustion productstream exiting the combustor to have a temperature of at least about700° C., at least about 750° C., at least about 800° C., at least about850° C., at least about 900° C., at least about 950° C., at least about1,000° C., at least about 1,050° C., at least about 1,100° C., at leastabout 1,200° C., at least about 1,300° C., at least about 1,400° C., atleast about 1,500° C., or at least about 1,600° C. In some embodiments,the combustion product stream may have a temperature of about 700° C. toabout 1,600° C., about 800° C. to about 1,600° C., about 850° C. toabout 1,500° C., about 900° C. to about 1,400° C., about 950° C. toabout 1,350° C., or about 1,000° C. to about 1,300° C.

As described above, the pressure of the CO₂ throughout the powerproduction cycle can be a critical parameter to maximize power cycleefficiency. While it can be important for the materials introduced intothe combustor to have a specifically defined pressure, it likewise canbe important for the combustion product stream to have a definedpressure. Specifically, the pressure of the combustion product streamcan be related to the pressure of the CO₂ circulating fluid that isintroduced into the combustor. In specific embodiments the pressure ofthe combustion product stream can be at least about 90% of the pressureof the CO₂ introduced into the combustor—i.e., in the circulating fluid.In further embodiments, the pressure of the combustion product streamcan be at least about 91%, at least about 92%, at least about 93%, atleast about 94%, at least about 95%, at least about 96%, at least about97%, at least about 98%, or at least about 99% of the pressure of theCO₂ introduced into the combustor.

The chemical makeup of the combustion product stream exiting thecombustor can vary depending upon the type of carbon containing fuelused. Importantly, the combustion product stream will comprise CO₂ thatwill be recycled and reintroduced into the combustor or further cycles,as more fully described below. Moreover, excess CO₂ (including CO₂produced by combustion of the fuel) can be withdrawn from the CO₂circulating fluid (particularly at a pressure suitable for directtransfer to a CO₂ pipeline) for sequestration or other disposal thatdoes not include release to the atmosphere. In further embodiments, thecombustion product stream may comprise one or more of water vapor, SO₂,SO₃, HCl, NO, NO₂, Hg, excess O₂, N₂, Ar, and possibly othercontaminants that may be preset in the fuel that is combusted. Thesematerials present in the combustion product stream may persist in theCO₂ circulating fluid stream unless removed, such as by processesdescribed herein. Such materials present in addition to the CO₂ may bereferred to herein as “secondary components.”

As seen in FIG. 5, the combustion product stream 40 can be directed to aturbine 320 wherein the combustion product stream 40 is expanded togenerate power (e.g., via a generator to produce electricity, which isnot shown in the illustration). The turbine 320 can have an inlet forreceiving the combustion product stream 40 and an outlet for release ofa turbine discharge stream 50 comprising CO₂. Although a single turbine320 is shown in FIG. 5, it is understood that more than one turbine maybe used, the multiple turbines being connected in series or optionallyseparated by one or more further components, such as a furthercombustion component, a compressing component, a separator component, orthe like.

Again, process parameters may be closely controlled in this step tomaximize cycle efficiency. Existing natural gas power plant efficiencyis critically dependent on turbine inlet temperatures. For example,extensive work has been done as great cost to achieve turbine technologyallowing for inlet temperatures as high as about 1,350° C. The higherthe turbine inlet temperature, the higher the plant efficiency, but alsothe more expensive the turbine is, and potentially, the shorter itslifetime. Some utilities are balking at paying the higher prices andhaving the risk of shorter life as well. Although the present inventioncan make use of such turbines to even further increase efficiency insome embodiments, such is not required. In specific embodiments, thepresent systems and methods can achieve the desired efficiency whileusing turbine inlet temperature in a much lower range, as describedabove. Thus, the invention may be characterized in terms of achieving aspecific efficiency, as described herein, while providing a combustionproduct stream to a turbine inlet at a defined temperature, as describedherein, which may be significantly less than temperatures recognized inthe art as necessary to achieve the same efficiency with the same fuel.

As noted above, the combustion product stream 40 leaving the combustor220 preferably has a pressure that is closely aligned to the pressure ofthe CO₂ circulating fluid 236 entering the combustor 220. In specificembodiments, the combustion product stream 40 is thus at a temperatureand pressure such that the CO₂ present in the stream is in asupercritical fluid state. When the combustion product stream 40 isexpanded across the turbine 320, the pressure of the stream is reduced.Preferably, this pressure drop is controlled such that the pressure ofthe combustion product stream 40 is in a defined ratio with the pressureof the turbine discharge stream 50. In certain embodiments, the pressureratio of the combustion product stream at the inlet of the turbinecompared to the turbine discharge stream at the out of the turbine isless than about 12. This can be defined as the inlet pressure (I_(n));to outlet pressure (O_(p)) ratio (i.e., I_(p)/O_(p)). In furtherembodiments, the pressure ratio can be less than about 11, less thanabout 10, less than about 9, less than about 8, or less than about 7. Inother embodiments, the inlet pressure to outlet pressure ratio a theturbine can be about 1.5 to about 12, about 2 to about 12, about 3 toabout 12, about 4 to about 12, about 2 to about 11, about 2 to about 10,about 2 to about 9, about 2 to about 8, about 3 to about 11, about 3 toabout 10, about 3 to about 9, about 3 to about 9, about 4 to about 11,about 4 to about 10, about 4 to about 9, or about 4 to about 8.

In specific embodiments, it can be desirable for the turbine dischargestream to be under conditions such that the CO₂ in the stream is nolonger in a supercritical fluid state but is rather in a gaseous state.For example, providing the CO₂ in a gaseous state can facilitate removalof any secondary components. In some embodiments, the turbine dischargestream has a pressure that is below the pressure where the CO₂ would bein a supercritical state. Preferably, the turbine discharge stream has apressure that is less than about 7.3 MPa, is less than or equal to about7 MPa, less than or equal to about 6.5 MPa, less than or equal to about6 MPa, less than or equal to about 5.5 MPa, less than or equal to about5 MPa, less than or equal to about 4.5 MPa, less than or equal to about4 MPa, less than or equal to about 3.5 MPa, less than or equal to about3 MPa, less than or equal to about 2.5 MPa, less than or equal to about2 MPa, or less than or equal to about 1.5 MPa. In other embodiments, thepressure of the turbine discharge stream can be about 1.5 MPa to about 7MPa, about 3 MPa to about 7 MPa, or about 4 MPa to about 7 MPa.Preferably, the pressure of the turbine discharge stream is less thanthe CO₂ condensing pressure at the cooling temperatures to beencountered by the stream (e.g., ambient cooling). Thus, it ispreferable according to the invention that the CO₂ downstream from theturbine 320 (and preferably upstream from the pressurization unit 620)be maintained in a gaseous state and not allowed to reach conditionswherein liquid CO₂ may form.

Although passage of the combustion product stream through the turbinemay lead to some amount of temperature decrease, the turbine dischargestream typically will have a temperature that could hinder removal ofany secondary components present in the combustion product stream. Forexample, the turbine discharge stream may have a temperature of about500° C. to about 1,000° C., about 600° C. to about 1,000° C., about 700°C. to about 1,000° C., or about 800° C. to about 1,000° C. Because ofthe relatively high temperature of the combustion product stream, it canbe beneficial for the turbine to be formed of materials capable ofwithstanding such temperatures. It also may be useful for the turbine tocomprise a material that provides good chemical resistance to the typeof secondary materials that may be present in the combustion productstream.

In some embodiments, it thus can be useful to pass the turbine dischargestream 50 through at least one heat exchanger 420 that cools the turbinedischarge stream 50 and provides a CO₂ circulating fluid stream 60having a temperature in a defined range. In specific embodiments, theCO₂ circulating fluid 60 leaving the heat exchanger 420 (or the finalheat exchanger in the series when two or more heat exchangers are used)has a temperature of less than about 200° C., less than about 150° C.,less than about 125° C., less than about 100° C., less than about 95°C., less than about 90° C., less than about 85° C., less than about 80°C., less than about 75° C., less than about 70° C., less than about 65°C., less than about 60° C., less than about 55° C., less than about 50°C., less than about 45° C., or less than about 40° C.

As noted above, it can be beneficial for the pressure of the turbinedischarge to have a pressure in a specific ratio with the pressure ofthe combustion product stream. In specific embodiments, the turbinedischarge stream will be directly passed through the one or more heatexchangers described herein without passing through any furthercomponents of the system. Thus, the pressure ratio also may be describedin relation to the ratio of the pressure of the combustion productstream as it exits the combustor compared to the pressure of the streamentering the hot end of the heat exchanger (or the first heat exchangerwhen a series of heat exchangers is used). Again, this pressure ratiopreferably is less than about 12. In further embodiments, the pressureratio of the combustion product stream to the stream entering the heatexchanger can be less than about 11, less than about 10, less than about9, less than about 8, or less than about 7. In other embodiments, thispressure ratio can be about 1.5 to about 10, about 2 to about 9, about 2to about 8, about 3 to about 8, or about 4 to about 8.

While the use of a transpiration cooled combustor allows for high heatcombustion, the systems and methods of the present invention can becharacterized by the ability to also provide a turbine discharge streamto a heat exchanger (or series or heat exchangers) at a temperature thatis sufficiently low to reduce costs associated with the system, increasethe lifespan of the heat exchanger(s), and improve performance andreliability of the system. In specific embodiments, the hottest workingtemperature for a heat exchanger in a system or method according to thepresent invention is less than about 1,100° C., less than about 1,000°C., less than about 975° C., less than about 950° C., less than about925° C. or less than about 900° C.

In certain embodiments, it can be particularly useful for the heatexchanger 420 to comprise at least two heat exchangers in series forreceiving the turbine discharge stream 50 and cool it to a desiredtemperature. The type of heat exchanger used can vary depending upon theconditions of the stream entering the heat exchanger. For example, theturbine discharge stream 50 may be at a relatively high temperature, asdescribed above, and it may thus be useful for the heat exchangerdirectly receiving the turbine discharge stream 50 to be formed fromhigh performance materials designed to withstand extreme conditions. Forexample, the first heat exchanger in the heat exchanger series maycomprise an INCONEL® alloy or similar material. Preferably, the firstheat exchanger in the series comprises a material capable ofwithstanding a consistent working temperature of at least about 700° C.,at least about 750° C., at least about 800° C., at least about 850° C.,at least about 900° C., at least about 950° C., at least about 1,000°C., at least about 1,100° C., or at least about 1,200° C. It also may beuseful for one or more of the heat exchangers to comprise a materialthat provides good chemical resistance to the type of secondarymaterials that may be present in the combustion product stream. INCONEL®alloys are available from Special Metals Corporation, and someembodiments can include austenitic nickel-chromium-based alloys.Examples of alloys that may be useful include INCONEL® 600, INCONEL®601, INCONEL® 601GC, INCONEL® 603XL, INCONEL® 617, INCONEL® 625,INCONEL® 625LCF, INCONEL® 686, INCONEL® 690, INCONEL® 693, INCONEL® 706,INCONEL® 718, INCONEL® 718SPF™, INCONEL® 722, INCONEL® 725, INCONEL®740, INCONEL® X-750, INCONEL® 751, INCONEL® MA754, INCONEL® MA758,INCONEL® 783, INCONEL® 903, INCONEL® N06230, INCONEL® C-276, INCONEL®G-3, INCONEL® HX, INCONEL® 22. An example of a favorable heat exchangerdesign is a diffusion bonded compact plate heat exchanger withchemically milled fins in the plates manufactured in a high temperaturematerial, such as one of the alloys described above. Suitable heatexchangers can include those available under the tradename HEATRIC®(available from Meggitt USA, Houston, Tex.).

The first heat exchanger in the series preferably can sufficientlytransfer heat from the turbine discharge stream such that one or morefurther heat exchangers present in the series can be formed of moreconventional materials—e.g., stainless steel. In specific embodiments,at least two heat exchangers or at least three heat exchangers are usedin a series to cool the turbine discharge stream to the desiredtemperature. The usefulness of using multiple heat exchangers in aseries particularly can be seen in the description below regardingtransfer of the heat from the turbine discharge stream to the CO₂circulating fluid to re-heat the circulating fluid prior to introductioninto the combustor.

In some embodiments, the methods and systems may be characterized asbeing a single stage combustion method or system. This can be achievedthough use of a high efficiency combustor, such as a transpirationcooled combustor described above. Essentially, the fuel can besubstantially completely combusted in the single combustor such that itis unnecessary to provide a series of combustors to completely combustthe fuel. Accordingly, in some embodiments, the inventive methods andsystems can be described such that the transpiration cooled combustor isthe only combustor. In further embodiments, the methods and systems canbe described such that the combustion occurs only in the singletranspiration cooled combustor prior to passage of the discharge streaminto the heat exchanger. In still further embodiments, the methods andsystems can be described such that the turbine discharge stream ispassed directly into the heat exchanger without passage through afurther combustor.

After cooling, the CO₂ circulating fluid stream 60 exiting the at leastone heat exchanger 420 can undergo further processing to separate outany secondary components remaining in the CO₂ circulating fluid stream60 from combustion of the fuel. As shown in FIG. 5, the circulatingfluid stream 60 can be directed to one or more separation units 520. Asdiscussed in greater detail below, the present invention can beparticularly characterized by the ability to provide a high efficiencymethod of generating power from combustion of a carbon containing fuelwith no atmospheric release of CO₂. This can be achieved, at least inpart, by using the CO₂ formed in combustion of the carbon containingfuel as the circulating fluid in the power production cycle. In someembodiments, though, the continuous combustion and recycling of CO₂ asthe circulating fluid may cause an accumulation of CO₂ in the system. Insuch cases, it can be useful to withdraw at least a portion of the CO₂from the circulating fluid (e.g., an amount approximately equivalent tothe quantity of CO₂ derived from combustion of the carbon containingfuel). Such withdrawn CO₂ can be disposed of by any suitable method. Inspecific embodiments, the CO₂ may be directed to a pipeline forsequestration or disposal by suitable means, as further described below.

It can be a requirement of a CO₂ pipeline system specification that theCO₂ entering the pipeline be substantially free of water to preventcorrosion of the carbon steel used for the pipeline. Although “wet” CO₂could be input directly into a stainless steel CO₂ pipeline, this is notalways possible and, in fact, it can be more desirable to use a carbonsteel pipeline because of cost concerns. Accordingly, in certainembodiments, water present in the CO₂ circulating fluid (e.g., waterformed during combustion of the carbon-containing fuel and persisting inthe combustion product stream, the turbine discharge stream, and the CO₂circulating fluid stream) can be removed mostly as a liquid phase fromthe cooled CO₂ circulating fluid stream. In specific embodiments, thiscan be achieved by providing the CO₂ circulating fluid (e.g., in agaseous state) at a pressure that is less than the point at which CO₂present in the gas mixture is liquefied when the gas mixture is cooledto the lowest temperature achieved with ambient temperature coolingmeans. For example, the CO₂ circulating fluid particularly can beprovided at a pressure of less than 7.38 MPa during separation ofsecondary components therefrom. An even lower pressure may be requiredif cooling means at a temperature in the low ambient range orsubstantially less than ambient are used. This allows for separation ofwater as a liquid and also minimizes contamination of the purified CO₂circulating stream 65 leaving the separation unit. This also can limitthe turbine discharge pressure to a value which is less than thecritical pressure of the turbine exhaust gas. The actual pressure candepend upon the temperature of the available ambient cooling means. Forexample, if the water separation takes place at 30° C., then a pressureof 7 MPa allows for a 0.38 MPa margin to the CO₂ condensing pressure. Insome embodiments, the CO₂ circulating fluid leaving the heat exchangerand entering the separation unit may be provided at a pressure of about2 MPa to about 7 MPa, about 2.25 MPa to about 7 MPa, about 2.5 MPa toabout 7 MPa, about 2.75 MPa to about 7 MPa, about 3 MPa to about 7 MPa,about 3.5 MPa to about 7 MPa, about 4 MPa to about 7 MPa, or about 4 MPato about 6 MPa. In other embodiments, the pressure may be substantiallythe same as the pressure at the turbine outlet.

In specific embodiments, the purified CO₂ circulating stream 65 afterwater separation comprises no water vapor or substantially no watervapor. In some embodiments, the purified CO₂ circulating stream can becharacterized as comprising water vapor in an amount of only less than1.5% on a molar basis, less than 1.25% on a molar basis, less than 1% ona molar basis, less than 0.9% on a molar basis, or less than 0.8% on amolar basis, less than 0.7% on a molar basis, less than 0.6% on a molarbasis, less than 0.5% on a molar basis, less than 0.4% on a molar basis,less than 0.3% on a molar basis, less than 0.2% on a molar basis, orless than 0.1% on a molar basis. In some embodiments, the purified CO₂circulating fluid stream can comprise water vapor only in an amount ofabout 0.01% to about 1.5% on a molar basis, about 0.01% to about 1% on amolar basis, about 0.01% to about 0.75% on a molar basis, about 0.01% toabout 0.5% on a molar basis, about 0.01% to about 0.25% on a molarbasis, about 0.05% to about 0.5% on a molar basis, or about 0.05% toabout 0.25% on a molar basis.

It can be highly advantageous to provide the CO₂ circulating fluid atthe above-defined temperature and pressure conditions to facilitateseparation of secondary components, such as water. In other words, thepresent invention can particularly provide for maintaining the CO₂circulating fluid under desired conditions such that the CO₂ and thewater in the CO₂ circulating fluid prior to separation are in desiredstates that facilitate separation. By providing the CO₂ circulatingfluid at a pressure as described above, the temperature of the fluidstream can be decreased to a point where water in the stream will be ina liquid state and thus be more easily separable from the gaseous CO₂.

In certain embodiments, it can be desirable to provide further dryingconditions so that the purified CO₂ circulating fluid is completely orsubstantially free of water. As noted above, separation of water fromthe CO₂ circulating fluid based on phase differences in the materialscan leave a minor portion (i.e., low concentration) of water remainingin the CO₂ circulating fluid. In some embodiments, it may be acceptableto continue with the CO₂ circulating fluid having the minor portion ofwater remaining therein. In other embodiments, it can be useful tosubject the CO₂ circulating fluid to further treatment to facilitateremoval of all or part of the remaining water. For example, lowconcentration of water may be removed by desiccant dryers or other meansthat would suitable in light of the present disclosure.

Providing the CO₂ circulating fluid to the separation units at thedefined pressure can be particularly beneficial for again maximizingefficiency of the power cycle. Specifically, providing the CO₂circulating fluid at the defined pressure range can allow for thepurified CO₂ circulating fluid in the gas phase to be compressed to ahigh pressure with minimal total power consumption. As described below,such pressurization can be required so that part of the purified CO₂circulating fluid can be recycled to the combustor and part can besupplied at a required pipeline pressure (e.g., about 10 MPa to about 20MPa). This further illustrates the benefits of minimizing the inlet tooutlet pressure ratio of the expansion turbine, as described above. Thisfunctions to increase the overall cycle efficiency and also to allow forthe discharge pressure from the turbine to be in the desirable rangedescribed above for separation of water and other secondary componentsfrom the CO₂ circulating fluid.

One embodiment of the flow of the CO₂ circulating fluid through aseparation unit 520 is illustrated in FIG. 6. As seen therein, the CO₂circulating fluid stream 60 from the heat exchanger can be passedthrough a cold water heat exchanger 530 that uses water to furtherremove heat from the CO₂ circulating fluid 60 (or any similarlyfunctioning device) and discharge a mixed phase CO₂ circulating fluid 61wherein the CO₂ remains a gas and the water in the CO₂ circulating fluidis converted to a liquid phase. For example, the passage of the CO₂circulating fluid 60 through the cold water heat exchanger 530 can coolthe CO₂ circulating fluid to a temperature of less than about 50° C.,less than about 55° C., less than about 40° C., less than about 45° C.,less than about 40° C., or less than about 30° C. Preferably, thepressure of the CO₂ circulating fluid is substantially unchanged bypassage through the cold water heat exchanger 530. The mixed phase CO₂circulating fluid 61 this is directed to a water separation unit 540wherein a liquid water stream 62 a is discharged from the separator 520.Also exiting the water separation unit 540 is the enriched CO₂circulating fluid stream 62 b. This enriched stream can directly exitthe separator 520 as the purified CO₂ circulating fluid stream 65. Inalternate embodiments (as illustrated by the streams and componentrepresented by dashed lines), the enriched CO₂ circulating fluid stream62 b may be directed to one or more additional separation units 550 forremoval of further secondary components, as more fully described below.In specific embodiments, any further secondary components of the CO₂circulating fluid can be removed after removal of water. The CO₂circulating fluid then exits the one or more additional separator unitsas the purified CO₂ circulating fluid 65. In some embodiments, however,the mixed phase CO₂ circulating fluid 61 may first be directed forremoval of one or more secondary components prior to removal of water,and the partially purified stream may then be directed to the waterseparation unit 540. One of skill with the knowledge of the presentdisclosure would be capable of envisioning the various combinations ofseparators that may be desirable, and all such combinations are intendedto be incorporated by the present invention.

As noted above, in addition to water, the CO₂ circulating fluid maycontain other secondary components, such as fuel-derived,combustion-derived, and oxygen-derived impurities. Such secondarycomponents also can be removed from the cooled, gaseous CO₂ circulatingfluid in and around the same time as water separation. For example, inaddition to water vapor, secondary components such as SO₂, SO₃, HCl, NO,NO₂, Hg, and excess O₂, N₂ and Ar can be removed. These secondarycomponents of the CO₂ circulating fluid (often recognized as impuritiesor contaminants) can all be removed from the cooled CO₂ circulatingfluid using appropriate methods (e.g., methods defined in U.S. PatentApplication Publication No. 2008/0226515 and European Patent ApplicationNos. EP1952874 and EP1953486, which are incorporated herein by referencein their entirety). The SO₂ and SO₃ can be converted 100% to sulfuricacid, while >95% of the NO and NO₂ can be converted to nitric acid. Anyexcess O₂ present in the CO₂ circulating fluid can be separated as anenriched stream for optional recycle to the combustor. Any inert gasespresent (e.g., N₂ and Ar) can be vented at low pressure to theatmosphere. In certain embodiments, the CO₂ circulating fluid can bethus purified such that the CO₂ derived from the carbon in the fuel thatis combusted can be ultimately delivered as a high density, pure stream.In specific embodiments, the purified CO₂ circulating fluid can compriseCO₂ in a concentration of at least 98.5% molar, at least 99% molar, atleast 99.5% molar, or at least 99.8% molar. Moreover, the CO₂circulating fluid can be provided at a desired pressure for direct inputinto a CO₂ pipeline—e.g., at least about 10 MPa, at least about 15 MPa,or at least about 20 MPa.

To summarize the foregoing, combustion of the carbon containing fuel 254in the presence of O₂ 242 and a CO₂ circulating fluid 236 in atranspiration cooled combustor 220 can form a combustion product stream40 having a relatively high temperature and pressure. This combustionproduct stream 40 comprising a relatively large amount of CO₂ can bepassed through a turbine 320 to expand the combustion product stream 40,thereby decreasing the pressure of the stream and generating power. Theturbine discharge stream 50 leaving the outlet of the turbine 320 is ata decreased pressure but still retains a relatively high temperature.Because of contaminants and impurities in the combustion product stream,it is beneficial to separate out such contaminants and impurities priorto recycling the CO₂ circulating fluid back into the system. To achievethis separation, the turbine discharge stream 50 is cooled by passagethrough the one or more heat exchangers 420. Separation of the secondaryproducts (e.g., water and any other contaminants and impurities) can beachieved as described above. In order to recycle the CO₂ circulatingfluid back into the combustor, it is necessary to both re-heat andre-pressurize the CO₂ circulating fluid. In certain embodiments, thepresent invention can be particularly characterized by theimplementation of specific process steps to maximize efficiency of thepower generation cycle while simultaneously preventing discharge ofpollutants (e.g., CO₂) into the atmosphere. This particularly can beseen in relation the re-heating and re-pressurizing of the cooled andpurified CO₂ circulating fluid exiting the separation unit.

As further illustrated in FIG. 5, the purified CO₂ circulating fluid 65leaving the one or more separation units 520 can be passed through oneor more pressurization units 620 (e.g., pumps, compressors, or the like)to increase the pressure of the purified CO₂ circulating fluid 65. Incertain embodiments, the purified CO₂ circulating fluid 65 can becompressed to a pressure of at least about 7.5 MPa or at least about 8MPa. In some embodiments, a single pressurization unit can be used toincrease the pressure of the purified CO₂ circulating fluid to thedesired pressure described herein for introduction into the combustor220.

In specific embodiments, pressurization can be carried out using aseries of two or more compressors (e.g., pumps) in the pressurizationunit 620. One such embodiment is shown in FIG. 7, wherein the purifiedCO₂ circulating fluid 65 is passed through a first compressor 630 tocompress the purified CO₂ circulating fluid 65 to a first pressure(which preferably is above the critical pressure of the CO₂) and thusform stream 66. Stream 66 can be directed to a cold water heat exchanger640 that withdraws heat (e.g., heat formed by the pressurizing action ofthe first compressor) and forms stream 67, which preferably is at atemperature that is near ambient. Stream 67 can be directed to a secondcompressor 650 that is used to pressurize the CO₂ circulating fluid to asecond pressure that is greater than the first pressure. As describedbelow, the second pressure can be substantially similar to the pressuredesired for the CO₂ circulating fluid when input (or recycled) to thecombustor.

In specific embodiments, the first compressor 630 can be used toincrease the pressure of the purified CO₂ circulating fluid 65 such thatthe purified CO₂ circulating fluid is transformed from a gaseous stateto a supercritical fluid state. In specific embodiments, the purifiedCO₂ circulating fluid can be pressurized in the first compressor 630 toa pressure of about 7.5 MPa to about 20 MPa, about 7.5 MPa to about 15MPa, about 7.5 MPa to about 12 MPa, about 7.5 MPa to about 10 MPa, orabout 8 MPa to about 10 MPa. The stream 66 exiting the first compressor630 (which is in a supercritical fluid state) is then passed through thecold water heat exchanger 640 (or any similarly functioning device) thatcan cool the CO₂ circulating fluid to a temperature sufficient to form ahigh density fluid that can more efficiently be pumped to an evengreater pressure. This can be significant in light of the large volumeof CO₂ that is being recycled for use as the circulating fluid. Pumpinga large volume of CO₂ in the supercritical fluid state can be asignificant energy drain on the system. The present, however, realizesthe beneficial increase in efficiency that can be provided by densifyingthe CO₂ and thus reducing the total volume of supercritical CO₂ that ispumped back to the combustor for recycle. In specific embodiments, theCO₂ circulating fluid can be provided at a density of at least about 200kg/m³, at least about 250 kg/m³, at least about 300 kg/m³, at leastabout 350 kg/m³, at least about 400 kg/m³, at least about 450 kg/m³, atleast about 500 kg/m³, at least about 550 kg/m³, at least about 600kg/m³, at least about 650 kg/m³, at least about 700 kg/m³, at leastabout 750 kg/m3, at least about 800 kg/m³, at least about 850 kg/m³, atleast about 900 kg/m³, at least about 950 kg/m³, or at least about 1,000kg/m³ after discharge from the cold water heat exchanger 640 (and priorto passage through the heat exchanger unit 420 for heating). In furtherembodiments, the density may be about 150 kg/m³ to about 1,1,100 kg/m³,about 200 kg/m³ to about 1,000 kg/m³, about 400 kg/m³ to about 950kg/m³, about 500 kg/m³ to about 900 kg/m³, or about 500 kg/m³ to about800 kg/m³.

In specific embodiments, passage of the stream 66 through the cold waterheat exchanger 640 can cool the CO₂ circulating fluid to a temperatureof less than about 60° C., less than about 50° C., less than about 40°C., or less than about 30° C. In other embodiments, the temperature ofthe CO₂ circulating fluid leaving the coldwater heat exchanger 640 asstream 67 can be about 15° C. to about 50° C., about 20° C. to about 45°C., or about 20° C. to about 40° C. The CO₂ circulating fluid in stream67 entering the second compressor 650 preferably is under conditionsthat facilitate the energy efficient pumping of the stream to a desiredpressure as described herein for introduction of the CO₂ circulatingfluid into the combustor. For example, the pressurized, supercriticalCO₂ circulating fluid stream 70 can be further pressurized to a pressureof at least about 12 MPa, at least about 15 MPa, at least about 16 MPa,at least about 18 MPa, at least about 20 MPa, or at least about 25 MPa.In some embodiments, the pressurized, supercritical CO₂ circulatingfluid stream 70 can be further pressurized to a pressure of about 15 MPato about 50 MPa, about 20 MPa to about 45 MPa, or about 25 MPa to about40 MPa. Any type of compressor capable of working under the notedtemperatures and capable of achieving the described pressures can beused, such as a high pressure multi-stage pump.

The pressurized CO₂ circulating fluid stream 70 leaving the one or morepressurization units 620 can be directed back to the heat exchangerspreviously used to cool the turbine discharge stream 50. As shown inFIG. 5, the pressurized CO₂ circulating fluid stream 70 first may bepassed through a stream splitter 720 that forms CO₂ pipeline fluidstream 80 and CO₂ circulating fluid stream 85 (which would besubstantially identical to CO₂ circulating fluid stream 70 except forthe actual amount of CO₂ present in the stream). Thus, in someembodiments, at least a portion of the CO₂ in the pressurized CO₂circulating fluid stream is introduced into a pressurized pipeline forsequestration. The amount of CO₂ removed from the CO₂ circulating fluidstream and directed to the pipeline (or other sequestration or disposalmeans) can vary depending upon the desired content of CO₂ to beintroduced into the combustor to control combustion temperature and theactual content of CO₂ present in the combustion discharge stream exitingthe combustor. In some embodiments, the amount of CO₂ withdrawn asdescribed above can be substantially the amount of CO₂ formed from thecombustion of the carbon containing fuel in the combustor.

To achieve a high efficiency operation, it can be beneficial for the CO₂circulating fluid leaving the pressurization unit 620 to be heated to atemperature at which the supercritical fluid has a much lower specificheat. This is equivalent to providing a very large heat input over acomparatively low temperature range. The use of an external heat source(e.g., a relatively low temperature heat source) to provide additionalheating for a portion of the recycled CO₂ circulating fluid allows theheat exchanger unit 420 to operate with a small temperature differencebetween turbine exhaust stream 50 and the recycled CO₂ circulating fluidstream 236 at the hot end of the heat exchanger unit 420 (or the firstheat exchanger when a series of two or more heat exchangers is used). Inspecific embodiments, passage of the pressurized CO₂ circulating fluidthrough the one or more heat exchangers can be useful for heating thepressurized CO₂ circulating fluid stream to a desired temperature forentry of the pressurized CO₂ circulating fluid stream into thecombustor. In certain embodiments, the pressurized CO₂ circulating fluidstream is heated to a temperature of at least about 200° C., at leastabout 300° C., at least about 400° C., at least about 500° C., at leastabout 600° C., at least about 700° C., or at least about 800° C. priorto input of the CO₂ circulating fluid stream into the combustor. In someembodiments, heating may be to a temperature of about 500° C. to about1,200° C., about 550° C. to about 1,000° C., or about 600° C. to about950° C.

FIG. 8 illustrates one embodiment of a heat exchange unit 420 whereinthree individual heat exchangers are used in series to withdraw heatfrom the turbine discharge stream 50 to provide a CO₂ circulating fluidstream 60 under suitable conditions for removal of secondary componentsand simultaneously add heat to the pressurized, supercritical CO₂circulating fluid stream 70 (or 85) prior to recycling and introductionof the CO₂ circulating fluid stream 236 into the combustor. As furtherdescribed below, the present systems and methods may be retrofitted toconventional power systems (e.g., coal fired power plants) to increaseefficiency and/or output thereof. In some embodiments, the heat exchangeunit 420 described as follows may thus be referred to as the primaryheat exchange unit in such a retrofit where a secondary heat exchangeunit also is used (as illustrated in FIG. 12). The secondary heatexchange unit thus could be one or more heat exchangers used tosuperheat a steam stream, for example. The use of the terms primary heatexchange unit and secondary heat exchange unit should not be construedas limiting the scope of the invention and are only used to provideclarity of description.

In the embodiments encompassed by FIG. 8, the turbine discharge stream50 enters the heat exchanger series 420 by first passing through thefirst heat exchanger 430 to provide stream 52, which will have a lowertemperature than the temperature of the turbine discharge stream 50. Thefirst heat exchanger 430 may be described as a high temperature heatexchanger as it receives the hottest stream in the series—i.e., theturbine discharge stream 50—and thus transfers heat in the highesttemperature range in the heat exchanger series 420. As described above,the first heat exchanger 430 receiving the relatively high temperatureturbine discharge stream 50 can comprise special alloys or othermaterials useful to make the heat exchanger suitable for withstandingthe noted temperatures. The temperature of the turbine discharge stream50 can be significantly reduced by passage through the first heatexchanger 430 (which also can apply to other embodiments where less thanthree or more than three individual heat exchangers are used). Incertain embodiments, the temperature of the stream 52 leaving the firstheat exchanger 430 can be lower than the temperature of the turbinedischarge stream 50 by at least about 100° C., at least about 200° C.,at least about 300° C., at least about 400° C., at least about 450° C.,at least about 500° C., at least about 550° C., at least about 575° C.,or at least about 600° C. In specific embodiments, the temperature ofstream 52 may be about 100° C. to about 800° C., about 150° C. to about600° C., or about 200° C. to about 500° C. In preferred embodiments, thepressure of the stream 52 leaving the first heat exchanger 430 issubstantially similar to the pressure of the turbine discharge stream50. Specifically, the pressure of the stream 52 leaving the first heatexchanger 430 can be at least 90%, at least 91%, at least 92%, at least93%, at least 94%, at least 95%, at least 96%, at least 97%, at least98%, at least 99%, at least 99.5%, or at least 99.8% of the pressure ofthe turbine discharge stream 50.

The stream 52 leaving the first heat exchanger 430 is passed through thesecond heat exchanger 440 to produce stream 56, which has a temperaturethat is less than the temperature of the stream 52 entering the secondheat exchanger 440. The second heat exchanger 440 may be described as anintermediate temperature heat exchanger as it transfers heat in anintermediate temperature range (i.e., a range less than the first heatexchanger 430 but greater than the third heat exchanger 450). In someembodiments, the temperature difference between the first stream 52 andthe second stream 56 can be substantially less than the temperaturedifference between the turbine discharge stream 50 and the stream 52leaving the first heat exchanger 430. In some embodiments, thetemperature of the stream 56 leaving the second heat exchanger 440 canbe lower than the temperature of the stream 52 entering the second heatexchanger 440 by about 10° C. to about 200° C., about 20° C. to about175° C., about 30° C. to about 150° C., or about 40° C. to about 140° C.In specific embodiments, the temperature of stream 56 may be about 75°C. to about 600° C., about 100° C. to about 400° C., or about 100° C. toabout 300° C. Again, it can be preferred for the pressure of the stream56 leaving the second heat exchanger 440 to be substantially similar tothe pressure of the stream 52 entering the second heat exchanger 440.Specifically, the pressure of the stream 56 leaving the second heatexchanger 440 can be at least 90%, at least 91%, at least 92%, at least93%, at least 94%, at least 95%, at least 96%, at least 97%, at least98%, at least 99%, at least 99.5%, or at least 99.8% of the pressure ofthe stream 52 entering the second heat exchanger 440.

The stream 56 leaving the second heat exchanger 440 is passed throughthe third heat exchanger 450 to produce the CO₂ circulating fluid stream60, which has a temperature that is less than the temperature of thestream 56 entering the third heat exchanger 450. The third heatexchanger 450 may be described as a low temperature heat exchanger as ittransfers heat in the lowest temperature range of the heat transferseries 420. In some embodiments, the temperature of the CO₂ circulatingfluid stream 60 leaving the third heat exchanger 450 can be lower thanthe temperature of the stream 56 entering the third heat exchanger 450by about 10° C. to about 250° C., about 15° C. to about 200° C., about20° C. to about 175° C., or about 25° C. to about 150° C. In specificembodiments, the temperature of stream 60 may be about 40° C. to about200° C., about 40° C. to about 100° C., or about 40° C. to about 90° C.Again, it can be preferred for the pressure of the CO₂ circulating fluidstream 60 leaving the third heat exchanger 450 to be substantiallysimilar to the pressure of the stream 56 entering the third heatexchanger 450. Specifically, the pressure of the CO₂ circulating fluidstream 60 leaving the third heat exchanger 450 can be at least 90%, atleast 91%, at least 92%, at least 93%, at least 94%, at least 95%, atleast 96%, at least 97%, at least 98%, at least 99%, at least 99.5%, orat least 99.8% of the pressure of the stream 56 entering the third heatexchanger 450.

The CO₂ circulating fluid stream 60 leaving the third heat exchanger 450(and thus leaving the heat exchanger unit 420 in general) can bedirected to the one or more separation units 520, as described above.Also as described above, the CO₂ circulating fluid stream can undergoone or more types of separation to remove secondary components from thestream, which is then pressurized for return to the combustor as therecycled, circulating fluid (optionally having a portion of the CO₂separated out for entry into a CO₂ pipeline or other means ofsequestration or disposal without venting to the atmosphere).

Returning to FIG. 8, the pressurized CO₂ circulating fluid stream 70 (or85 if first passed through a separation apparatus, as shown in FIG. 5),can be directed back through the same series of three heat exchangers sothat the heat originally withdrawn via the heat exchangers can be usedto impart heat to the pressurized CO₂ circulating fluid stream 70 priorto entry into the combustor 220. Typically, heat imparted to thepressurized CO₂ circulating fluid stream 70 by passage through the threeheat exchangers (450, 440, and 430) can be relatively proportional tothe amount of heat withdrawn by the heat exchangers as described above.

In certain embodiments, the invention may be characterized by thetemperature difference of the streams exiting and entering the cold endof the heat exchanger (or the last heat exchanger in a series).Referring to FIG. 8, this specifically may relate to the temperaturedifference of streams 60 and 70. This temperature difference of thestreams at the cold end of the heat exchanger (of the last heatexchanger in a series) specifically is greater than zero and may be inthe range of about 2° C. to about 50° C., about 3° C. to about 40° C.,about 4° C. to about 30° C., or about 5° C. to about 20° C.

In some embodiments, the pressurized CO₂ circulating fluid stream 70 canbe passed directly through the three heat exchangers in series. Forexample, the pressurized CO₂ circulating fluid stream 70 (i.e., at arelatively low temperature) can pass through the third heat exchanger450 to form stream 71 at an increased temperature, which can be passeddirectly through the second heat exchanger 440 to form stream 73 at anincreased temperature, which can be passed directly through the firstheat exchanger 430 to form the high temperature, pressurized CO₂circulating fluid stream 236 that can be directed to the combustor 220.

In particular embodiments, however, the present invention can becharacterized by the use of an external heat source to further increasethe temperature of the recycled CO₂ circulating fluid. For example, asillustrated in FIG. 8, after passage of the pressurized CO₂ circulatingfluid stream 70 through the third heat exchanger 450, the formed stream71, instead of passing directly to the second heat exchanger 440 can bepassed through a splitting component 460 that splits stream 71 into twostreams 71 b and 72 a. Stream 71 b can be passed through the second heatexchanger 440 as otherwise described above. Stream 72 a can be passedthrough a side heater 470 that can be used to impart an additionalamount of heat to the pressurized CO₂ circulating fluid stream 70 inaddition to the heat imparted by the heat exchangers themselves.

The relative amounts of the pressurized CO₂ circulating fluid from thestream 71 that are directed to the second heat exchanger 440 and theside heater 470 can vary depending upon the working conditions of thesystem and the desired final temperature of the pressurized CO₂circulating fluid stream for entry into the combustor 220. In certainembodiments, the molar ratio of CO₂ in the stream 71 b directed to thesecond heat exchanger 440 and the stream 72 a directed to the sideheater 470 can be about 1:2 to about 20:1 (i.e., about 1 mole of CO₂ instream 71 b per 2 moles of CO₂ in stream 72 a to about 20 moles of CO₂in stream 71 b per 1 mole of CO₂ in stream 72 a). In furtherembodiments, the molar ratio of CO₂ in the stream 71 b directed to thesecond heat exchanger 440 and the stream 72 a directed to the sideheater 470 can be about 1:1 to about 20:1, about 2:1 to about 16:1,about 2:1 to about 12:1, about 2:1 to about 10:1, about 2:1 to about8:1, or about 4:1 to about 6:1.

The side heater can comprise any apparatus useful for imparting heat tothe CO₂ circulating fluid. In some embodiments, the energy (i.e., heat)provided by the side heater can be input into the system from an outsidesource. In particular embodiments according to the invention, however,the efficiency of the cycle can be increased by utilizing waste heatthat is generated at one or more points in the cycle. For example,production of O₂ for input into the combustor can produce heat. Knownair separation units can generate heat as a by-product of the separationprocess. Moreover, it can be useful for the O₂ to be provided at anincreased pressure, such as described above, and such pressurization ofthe gas can also generate heat as a by-product. For example, O₂ may beproduced by the operation of a cryogenic air separation process in whichthe oxygen is pressurized in the process by pumping liquid oxygen thatis efficiently heated to ambient temperature conserving refrigeration.Such a cryogenic pumped oxygen plant can have two air compressors, bothof which can be operated adiabatically with no inter-stage cooling sothat the hot, pressurized air can be cooled down to a temperature thatis close to and/or greater than the temperature of the stream that isheated by the external source (e.g., stream 72 a in FIG. 8). In knownart settings, such heat is unutilized or can actually be a drain on thesystem as secondary cooling systems are required to eliminate theby-product heat. In the present invention, however, a coolant may beused to withdraw the generated heat from the air separation process andprovide the heat to the side heater illustrated in FIG. 8. In otherembodiments, the side heater could itself be the air separation unit (oran associated device), and the CO₂ circulating fluid (e.g., stream 72 ain FIG. 8) could itself be directly circulated through a coolant systemon or associated with the air separation unit to withdraw the heatgenerated in the air separation process. More specifically, the addedheat can be obtained by operating the CO₂ compressor adiabatically andremoving the heat of compression in after-coolers against a circulatingheat transfer fluid which transfers the heat of compression to heat partof the high pressure CO₂ circulating fluid or by direct heat transfer tothe high pressure recycled CO₂ circulating fluid stream (e.g., stream 72a in FIG. 8). Further, the addition of such heat is not necessarilylimited to the position described in relation to FIG. 8 but could beinput to the cycle at any point after separation of the secondarycomponents from the CO₂ circulating fluid (but preferably before passageof the CO₂ circulating fluid through the heat exchanger directlyupstream from the input into the combustor). Of course, any similarmethod of utilizing waste generated in the power production cycle alsowould be encompassed by the present disclosure, such as using a supplyof steam at a suitable condensing temperature or the hot exhaust gasfrom a conventional open cycle gas turbine.

The amount of heat imparted by the side heater 470 can vary dependingupon the materials and apparatuses used as well as the ultimatetemperature to be achieved for the CO₂ circulating fluid stream 236 forentry into the combustor 220. In some embodiments, the side heater 470effectively increases the temperature of the stream 72 a by at leastabout 10° C., at least about 20° C., at least about 30° C., at leastabout 40° C., at least about 50° C., at least about 60° C., at leastabout 70° C., at least about 80° C., at least about 90° C., or at leastabout 100° C. In other embodiments, the side heater 470 effectivelyincreases the temperature of the stream 72 a by about 10° C. to about200° C., about 50° C. to about 175° C., or about 75° C. to about 150° C.In specific embodiments, the side heater 470 increases the temperatureof stream 72 a to within at least about 15° C., within at least about12° C., within at least about 10° C., within at least about 7° C., orwithin at least about 5° C. of the temperature of stream 73 leaving heatexchanger 440.

By this addition of a further heat source, stream 71 leaving the thirdheat exchanger 450 can be superheated beyond the ability of theavailable heat in the second heat exchanger 440 to heat stream 71 if theentire amount of CO₂ in the stream was directed through the second heatexchanger 440. By splitting the stream, the heat available in the secondheat exchanger 440 can be fully imparted to the partial content of CO₂circulating fluid in stream 71 b while the heat available from the sideheater 470 can be fully imparted to the partial content of the CO₂circulating fluid in stream 72 a. Thus, it can be seen that thetemperature of the combined streams entering the first heat exchanger430 when the alternative splitting method is utilized can be greaterthan the temperature of stream 73 exiting the second heat exchanger 440if the full amount of the CO₂ circulating fluid in stream 71 is directedto the second heat exchanger 440 instead of being split and separatelyheated, as described above. In some embodiments, the increased heatgained by the splitting method can be significant enough to limitwhether or not the CO₂ circulating fluid stream 236 is sufficientlyheated prior to entering the combustor.

As seen in FIG. 8, stream 71 b leaving the splitter 460 is passedthrough the second heat exchanger 440 to form stream 73, which isdirected to the mixer 480 that combines stream 73 with stream 72 bdischarged from the side heater 470. The combined stream 74 is thenpassed through the first heat exchanger 430 to heat the CO₂ circulatingfluid to a temperature that is substantially close to the temperature ofthe turbine discharge stream when entering the first heat exchanger 430.This closeness in temperatures of the fluid streams at the hot end ofthe first heat exchanger can apply to further embodiments of theinvention where less than three or more than three heat exchangers areused and can apply to the first heat exchanger through which the CO₂circulating fluid is passed after discharge from the turbine. Theability to achieve this closeness in temperature of the fluid streams atthe hot end of the first heat exchanger can be a key characteristic ofthe invention for attaining desired efficiency levels. In certainembodiments, the difference between the temperature of the turbinedischarge stream entering the first heat exchanger in line from theturbine (i.e., after expanding in the turbine) and the temperature ofthe CO₂ circulating fluid stream leaving the heat exchanger forrecycling into the combustor can be less than about 80° C., less thanabout 75° C., less than about 70° C., less than about 65° C., less thanabout 60° C., less than about 55° C., less than about 50° C., less thanabout 45° C., less than about 40° C., less than about 35° C., less thanabout 30° C., less than about 25° C., less than about 20° C., or lessthan about 15° C.

As can be seen from the foregoing, the efficiency of the systems andmethods of the present invention can be greatly facilitated by precisecontrol of the temperature difference at the hot end of heat exchanger420 (or the first heat exchanger 430 in the series illustrated in FIG.8) between the turbine discharge stream 50 and the recycled CO₂circulating fluid stream 236. In preferred embodiments, this temperaturedifference is less than 50° C. Although not wishing to be bound bytheory, it has been found according to the present invention that heatavailable for heating the recycled CO₂ circulating fluid (e.g., heatwithdrawn from the turbine discharge stream in the one or more heatexchangers) can be inadequate for sufficiently heating the total streamof recycled CO₂ circulating fluid. The present invention has realizedthat this can be overcome by dividing stream 71 so that stream 71 benters the heat exchanger 440 and stream 72 a enters the external heatsource 470 that provides the additional, external source of heat thatraises the temperature of stream 72 b leaving external heat source 470to be substantially close to the temperature of stream 73 leaving theheat exchanger 440, as already described above. Streams 72 b and 73 thencombine to form stream 74. The flow-rate of stream 71 b (and also stream72 a) can be controlled by the temperature difference at the cold end ofheat exchanger 440. The amount of external heat required to overcome theheat inadequacy described above can be minimized by making thetemperature of stream 56 as low as possible and then minimizing the coldend temperature difference of heat exchanger 440. The water vaporpresent in stream 56 arising from the combustion products reaches itsdew point at a temperature that depends on the composition of the stream56 and its pressure. Below this temperature the condensation of watergreatly increases the effective mCp of stream 56 to stream 60 andprovides all the heat required to heat the total recycle stream 70 tostream 71. The temperature of stream 56 leaving heat exchanger 440preferably can be within about 5° C. of the dew point of stream 56. Thetemperature difference at the cold end of heat exchanger 440 betweenstreams 56 and 71 preferably can be at least about 3° C., at least about6° C., at least about 9° C., at least about 12° C., at least about 15°C., at least about 18° C., or at least about 20° C.

Returning to FIG. 5, the CO₂ circulating fluid 236 can be preheatedprior to being recycled into the combustor 220, such as described inrelation to the at least one heat exchanger 420, which receives the hotturbine discharge stream 50 after passage through the expansion turbine320. To maximize the efficiency of the cycle, it can be useful tooperate the expansion turbine 320 at as high an inlet temperature aspossible consistent with the available materials of construction of thehot gas inlet path and the highly stressed turbine blades, as well asthe maximum temperature allowable in the heat exchanger 420 consistentwith the system operating pressures. The hot inlet path of the turbineinlet stream and the first rows of turbine blades can be cooled by anyuseful means. In some embodiments, efficiency can be maximized by usingpart of the high pressure, recycle CO₂ circulating fluid. Specifically,the lower temperature CO₂ circulating fluid (e.g., in the range of about50° C. to about 200° C.) can be withdrawn from the cycle before the coldend of the heat exchanger 420 or from an intermediate point in the heatexchanger 420 when a series of multiple heat exchanger units is utilized(e.g., from streams 71, 72 a, 71 b, 72 b, 73, or 74 in FIG. 8). Theblade cooling fluid can be discharged from holes in the turbine bladeand be input directly into the turbine flow.

Operation of a high efficiency burner, such as the transpiration cooledcombustor described herein, can produce a combustion gas which is anoxidizing gas with excess oxygen concentration (such as in the range ofabout 0.1% to about 5% molar). Alternately, the combustor can produce acombustion gas which is a reducing gas with certain concentrations ofone or more of H₂, CO, CH₄, H₂S, and NH₃. This is particularlybeneficial in that it becomes possible according to the invention to usea power turbine with only one turbine unit or a series of turbine units(e.g., 2, 3, or more units). Beneficially, in specific embodiments usinga series of units, all of the units can operate with the same inlettemperature, and this allows for maximizing power output for a givenfirst turbine feed pressure and overall pressure ratio.

One example of a turbine unit 320 utilizing two turbines 330, 340operated in series in the reducing mode is shown in FIG. 9. As seentherein, the combustion product stream 40 is directed to the firstturbine 330. In such embodiments, the combustion product stream 40 isdesigned (e.g., through control of the fuel used, the amount of O₂ used,and the operating conditions of the combustor) to be a reducing gas withone or more combustible components therein, as described above. Thecombustion product stream 40 is expanded across the first turbine 330 toproduce power (such as in association with an electric generator, notshown in this illustration) and form a first discharge stream 42. Priorto introduction into the second turbine 340, a predetermined amount ofO₂ can be added to the first turbine discharge stream 42 to combust theflammable components present in the first turbine discharge stream 42.This leaves excess oxygen while raising the inlet temperature at thesecond turbine unit 340 to substantially the same value as the inlettemperature for the first turbine unit 330. For example, the temperatureof the discharge stream 42 from the first turbine unit 330 may be in therange of about 500° C. to about 1,000° C. When in the reducing mode, theaddition of the O₂ to the discharge stream 42 at this temperature cancause the gas in the stream to be heated by combustion of the excessfuel gas to a temperature in the range of about 700° C. to about 1,600°C., which is substantially the same temperature range as combustionproduct stream 40 exiting the combustion chamber 220 prior to enteringthe first turbine unit 330. In other words, the operating temperature atthe inlet of each of the two turbines is substantially the same. Inspecific embodiments, the operating temperature at the inlet of theturbines differs by no more than about 10%, no more than about 9%, nomore than about 8%, no more than about 7%, or no more than about 6%, nomore than about 5%, no more than about 4%, no more than about 3%, nomore than about 2%, or no more than about 1%. Similar re-heat steps forfurther turbine units also could be accomplished to the extent residualfuel remains. Combustion can be enhanced by the use of a suitablecatalyst in the oxygen fed combustion space, if required.

In certain embodiment, a power cycle as described herein can be used toretrofit existing power stations, such as by introducing a hightemperature, high pressure heating fluid (e.g., the turbine dischargestream described herein) into the steam superheating cycle of aconventional Rankine cycle power station. This could be a coal fired ora nuclear power station with a boiling water reactor (BWR) orpressurized water reactor (PWR) heat cycle. This effectively increasesthe efficiency and power output of the steam Rankine power station bysuperheating the steam to a far higher temperature than the maximumtemperature of superheated steam produced in the existing system. In thecase of a pulverized coal fired boiler, the steam temperatures arecurrently up to a maximum of about 600° C. while the steam conditions ina nuclear power station are generally up to about 320° C. Using thesuperheating possible with the heat exchange in the present inventivesystems and methods, the steam temperature can be raised to over 700° C.This leads to direct conversion of heat energy to extra shaft powersince the additional fuel burned to superheat the steam is converted toextra power in the steam based power station without increasing thequantity of steam condensed. This may be accomplished by providing asecondary heat exchange unit. For example, the turbine discharge streamdescried in relation to the present, inventive methods and systems couldbe directed through the secondary heat exchange unit prior to passagethrough the primary heat exchange unit, as otherwise described herein.The heat obtained in the secondary heat exchange unit could be used tosuperheat the steam from the boiler, as described above. The superheatedsteam could be directed to one or more turbines to generate power. Theturbine discharge stream, after passage through the secondary heatexchange unit, could then be directed to the primary heat exchange unit,as otherwise described herein. Such system and method is described inExample 2 and illustrated in FIG. 12. In addition, it is possible totake low pressure steam from the inlet of the final steam turbine anduse this for heating part of the recycled CO₂ circulating fluid, asdescribed above. In specific embodiments, condensate from the steampower station can be heated to an intermediate temperature prior tode-aeration using the CO₂ circulating fluid stream, which leaves thecold end of the heat exchanger unit (for example, at a temperature about80° C. in some embodiments). This heating normally uses bleed steamtaken from the inlet to the final LP steam turbine stage so the neteffect on the steam power station efficiency of the deficit for thepresent side-stream heating is compensated by the preheating ofcondensate, which conserves bleed steam.

The above-described general method for power production (i.e., a powercycle) can be implemented according to the invention using a suitablepower production system as described herein. Generally, a powerproduction system according to the invention may comprise any of thecomponents described herein in relation to the power production method.For example, a power production system may comprise a combustor forcombusting a carbon containing fuel in the presence of O₂ and a CO₂circulating fluid. Specifically, the combustor may be a transpirationcooled combustor, as described herein; however, other combustors capableof operating under the conditions otherwise described herein also couldbe used. The combustor specifically may be characterized in relation tothe combustion conditions under which it operates, as well as specificcomponents of the combustor itself. In some embodiments, the system maycomprise one or more injectors for providing the carbon containing fuel(and optionally a fluidizing medium) the O₂, and the CO₂ circulatingfluid. The system may include components for liquid slag removal. Thecombustor may produce a fuel gas at a temperature at which solid ashparticles can be effectively filtered from the gas, and the gas can bemixed with quench CO₂ and be burned in a second combustor. The combustorcan include at last one combustion stage that combusts the carboncontaining fuel in the presence of the CO₂ circulating fluid to providea combustion product stream comprising CO₂ at a pressure and temperatureas described herein.

The system further may comprise a power production turbine in fluidcommunication with the combustor. The turbine can have an inlet forreceiving the combustion product stream and an outlet for release of aturbine discharge stream comprising CO₂. Power can be produced as thefluid stream expands, the turbine being designed to maintain the fluidstream at a desired pressure ratio (I_(p)/O_(p)), as described herein.

The system further can comprise at least one heat exchanger in fluidcommunication with the turbine for receiving the turbine dischargestream and cooling the stream to form a cooled CO₂ circulating fluidstream. Likewise, the at least one heat exchanger can be used forheating the CO₂ circulating fluid that is input into the combustor. Theheat exchanger(s) specifically may be characterized in relation to thematerials from which it is constructed that allows for operation underspecific conditions as described herein.

The system also can comprise one or more devices for separating the CO₂circulating fluid stream exiting the heat exchanger into CO₂ and one ormore further components for recovery or disposal. Specifically, thesystem may comprise means for separating water (or other impuritiesdescribed herein) from the CO₂ circulating fluid stream.

The system further can comprise one or more devices (e.g., compressors)in fluid communication with the at least one heat exchanger (and/or influid communication with one or more of the separation devices) forcompressing the purified CO₂ circulating fluid. Moreover, the system cancomprise means for separating the CO₂ circulating fluid into twostreams, one stream for passage through the heat exchanger and into thecombustor and a second stream for delivery into a pressurized pipeline(or other means for sequestration and/or disposal of the CO₂).

In some embodiments, even further components may be included in thesystem. For example, the system may comprise an O₂ separation unit fordelivery of O₂ into the combustor (or into an injector or similar devicefor mixing the O₂ with one or more further materials). In someembodiments, the air separation unit may generate heat. Thus, it can beuseful for the system to further comprise one or more heat transfercomponents that transfers heat from the air separation unit to the CO₂circulating fluid stream upstream from the combustor. In furtherembodiments, a system according to the invention may comprise any andall of the components otherwise described herein in relation the powergeneration cycle and the methods of generating power.

In further embodiments, the invention encompasses systems and methodsparticularly useful in power production using a fuel (such as coal) thatleaves an incombustible residue on combustion. In certain embodiments,such incombustible materials can be removed from the combustion productstream through use of an appropriate device, such as a contaminantremoval apparatus illustrated in FIG. 4. In other embodiments, however,it can be useful to manage incombustible materials though use of amulti-combustor system and method, such as illustrated in FIG. 10.

As shown in FIG. 10, the coal fuel 254 can be passed through a millapparatus 900 to provide a powdered coal. In other embodiments, the coalfuel 254 could be provided in a particularized condition. In specificembodiments, the coal may have an average particle size of about 10 μmto about 500 μm, about 25 μm to about 400 μm, or about 50 μm to about200 μm. In other embodiments, the coal may be described in that greaterthan 50%, 60%, 70%, 80%, 90%, 91%, 92%, 93%, 94%, 95%, 96%, 97%, 98%,99%, or 99.5% of the coal particles have an average size of less thanabout 500 μm, 450 μm, 400 μm, 350 μm, 300 μm, 250 μm, 200 μm, 150 μm, or100 μm. The powdered coal can be mixed with a fluidizing substance toprovide the coal in the form of a slurry. In FIG. 10, the powdered coalis combined in the mixer 910 with a CO₂ side draw 68 from the recycledCO₂ circulating fluid. In FIG. 10, the CO₂ side draw 68 is withdrawnfrom stream 67, which has undergone processing to provide the CO₂circulating fluid in a supercritical, high density state. In specificembodiments, the CO₂ used to form the coal slurry can have a density ofabout 450 kg/m³ to about 1,100 kg/m³. More particularly, the CO₂ sidedraw 68 may cooperate with the particulate coal to form a slurry 255having, for example, between about 10 weight % and about 75 weight % orbetween about 25 weight % and about 55 weight % of the particulate coal.Moreover, the CO₂ from the side draw 68 used to form the slurry may beat a temperature of less than about 0° C., less than about −10° C., lessthan about −20° C., or less than about −30° C. In further embodiments,the CO₂ from the side draw 68 used to form the slurry may be at atemperature of about 0° C. to about −60° C., about −10° C. to about −50°C., or about −18° C. to about −40° C.

The powdered coal/CO₂ slurry 255 is transferred from the mixer 910 viapump 920 to a partial oxidation combustor 930. An O₂ stream is formedusing an air separation unit 30 that separates air 241 into purified O₂,as described herein. The O₂ stream is split into O₂ stream 243, which isdirected to the partial oxidation combustor 930, and O₂ stream 242,which is directed to the combustor 220. In the embodiment of FIG. 10, aCO₂ stream 86 is withdrawn from the recycled CO₂ circulating fluidstream 85 for use in cooling the partial oxidation combustor 930. Infurther embodiments, CO₂ for use in cooling the partial oxidationcombustor 930 may be taken from stream 236 instead of stream 86 or, theCO₂ may be taken from both stream 86 and stream 236. Preferably, theamount of CO₂ withdrawn is sufficient to cool the temperature of stream256 such that ash is present in a solid form that can be safely removed.As otherwise described herein, the CO₂, coal, and O₂ are provided to thepartial oxidation combustor 930 in ratios such that the coal is onlypartially oxidized to produce a partially oxidized combustion productstream 256 comprising CO₂ along with one or more of H₂, CO, CH₄, H₂S,and NH₃. The CO₂, coal, and O₂ also are introduced into the partialoxidation combustor 930 in necessary ratios such that the temperature ofthe partially oxidized combustion product stream 256 is sufficiently lowthat all of the ash present in the stream 256 is in the form of solidparticles that can be easily removed by one or more cyclone separatorsand/or filters. The embodiment of FIG. 10 illustrates ash removal viafilter 940. In specific embodiments, the temperature of the partiallyoxidized combustion stream 256 can be less than about 1,100° C., lessthan about 1,000° C., less than about 900° C., less than about 800° C.,or less than about 700° C. In further embodiments, the temperature ofthe partially oxidized combustion stream 256 can be about 300° C. toabout 1,000° C., about 400° C. to about 950° C., or about 500° C. toabout 900° C.

The filtered, partially oxidized combustion stream 257 can be directlyinput into the second combustor 220, which can be a transpiration cooledcombustor, as otherwise described herein. This input is provided alongwith the O₂ stream 242, and the recycled CO₂ circulating fluid stream236. Combustion at this point can proceed similarly as otherwisedescribed herein. The combustible materials in the partially oxidizedcombustion stream 256 are combusted in combustor 220 in the presence ofO₂ and CO₂ to provide the combustion stream 40. This stream is expandedacross a turbine 320 to produce power (e.g., via generator 1209). Theturbine discharge stream 50 is passed through a heat exchanger unit 420(which may be a series of heat exchangers, such as described in relationto FIG. 8). The CO₂ circulating fluid stream 60 is passed through thecold water heat exchanger 530 to form stream 61, which is passed toseparator 540 for removal of secondary components (e.g., H₂O, SO₂, SO₄,NO₂, NO₃, and Hg) in stream 62. The separator 540 may be substantiallysimilar to the column 1330 described in relation to FIG. 12 below.Preferably, the separator 540 comprises a reactor that provides acontactor with sufficient residence times such that the impurities canreact with water to form materials (e.g., acids) that are easilyremoved. The purified CO₂ circulating fluid stream 65 is passed througha first compressor 630 to form stream 66, which is cooled with coldwater heat exchanger 640 to provide the supercritical, high density CO₂circulating fluid 67. As described above, a portion of stream 67 can bewithdrawn as stream 68 for use as the fluidizing medium in the mixer 910to form the coal slurry stream 255. The supercritical, high density CO₂circulating fluid stream 67 otherwise is further pressurized incompressor 650 to form the pressurized, supercritical, high density CO₂circulating fluid stream 70. A portion of the CO₂ in stream 70 may bewithdrawn at point 720, as described herein in relation to FIG. 5 andFIG. 11 to provide stream 80 to a CO₂ pipeline or other means ofsequestration. The remaining portion of the CO2 proceeds as pressurized,supercritical, high density CO₂ circulating fluid stream 85, a portionof which may be withdrawn as stream 86 to use for cooling of the partialoxidation combustor 930, as described above. Otherwise, the stream 85 ispassed back through the heat exchanger 420 (or series of heatexchangers, as described in relation to FIG. 8) to heat the stream andultimately form the recycled CO₂ circulating fluid stream 236 for inputto the combustor 220. As described above, an external heat source may beused in combination with heat exchanger unit 420 to provide thenecessary efficiency. Likewise, other system and method parameters asotherwise described herein can be applied to the system and methodaccording to FIG. 10, such as stream temperatures and pressures, as wellas other operating conditions for the turbine unit 320, the heatexchanger unit 420, the separation unit 520, and the compressor unit630.

EXPERIMENTAL

The invention is further described below in relation to specificexamples. The examples are provided to illustrate certain embodiments ofthe invention and should not be construed as limiting of the invention.

Example 1 System and Method for Power Production with Methane CombustionUsing a Recycled CO₂ Circulating Fluid

One specific example of a system and method according to the presentinvention is illustrated, in FIG. 11. The following descriptiondescribes the system in relation to a specific cycle under specificconditions using computer modeling.

In this model, a methane (CH₄) fuel stream 254 at a temperature of 134°C. and a pressure of 30.5 MPa is combined with a recycled CO₂circulating fluid stream 236 at a temperature of 860° C. and a pressureof 30.3 MPa (and thus in a supercritical fluid state) in a mixer 252prior to introduction into a transpiration cooled combustor 220. An airseparation unit 30 is used to provide concentrated O₂ 242 at atemperature of 105° C. and a pressure of 30.5 MPa. The air separationunit also produces heat (Q) that is drawn off for use in the process.The O₂ 242 is combined in the combustor 220 with the methane fuel stream254 and the CO₂ circulating fluid 236 where combustion occurs to providecombustion product stream 40 at a temperature of 1189° C. and a pressureof 30 MPa. The CO₂, O₂, and methane are provided in a molar ratio ofabout 35:2:1 (i.e., lbmol/hr—pound moles per hour). Combustion in thisembodiment uses energy input at a rate of 344,935 Btu/hr (363,932kJ/hr).

The combustion product stream 40 is expanded across the turbine 320 toproduce the turbine discharge stream 50 at a temperature of 885° C. anda pressure of 5 MPa (the CO₂ in the turbine discharge stream 50 being ina gaseous state). Expansion of the combustion product stream 40 acrossthe turbine 320 produces power at a rate of 83.5 kilowatts per hour(kW/hr).

The turbine discharge stream 50 is then passed through a series of threeheat exchangers to successively cool the stream for removal of secondarycomponents. Passage through the first heat exchanger 430 produces stream52 at a temperature of 237° C. and a pressure of 5 MPa. Stream 52 ispassed through the second heat exchanger 440 to produce stream 56 at atemperature of 123° C. and a pressure of 5 MPa. Stream 56 is passedthrough the third heat exchanger 450 to produce stream 60 at atemperature of 80° C. and a pressure of 5 MPa.

After passage of the recycle CO₂ circulating fluid through the series ofheat exchangers, the stream 60 is even further cooled by passage througha cold water heat exchanger 530. Water (C) at a temperature of 24° C. iscycled through the cold water heat exchanger 530 to cool the CO₂circulating fluid stream 60 to a temperature of 27° C. and thus condenseany water present in the CO₂ circulating fluid stream. The cooled CO₂circulating fluid stream 61 is then passed through a water separationunit 540 such that liquid water is removed and discharged as stream 62a. The “dried” CO₂ circulating fluid stream 65 is discharged from thewater separation unit 540 at a temperature of 34° C. and a pressure of 3MPa.

The dry CO₂ circulating fluid stream 65 (which is still in a gaseousstate) is next passed through a first compression unit 630 in a two steppressurization scheme. The CO₂ circulating fluid stream is pressurizedto 8 MPa, which likewise raises the temperature of the CO₂ circulatingfluid stream to 78° C. This requires a power input of 5.22 kW/hr. Thissupercritical fluid CO₂ circulating fluid stream 66 is then passedthrough a second cold water heat exchanger 640 where the supercriticalfluid CO₂ circulating fluid stream 66 is cooled with water at atemperature of 24° C. to produce a cooled supercritical fluid CO₂circulating fluid stream 67 at a temperature of 27° C., a pressure of 8MPa, and a density of 762 kg/m³. This stream is then passed through asecond compression unit 650 to form the pressurized CO₂ circulatingfluid stream 70 at a temperature of 69° C. and a pressure of 30.5 MPa.This requires a power input of 8.23 kW/hr. This stream is passed througha pipeline splitter 720 whereby 1 lbmol of CO₂ is directed to apressurized pipeline via stream 80, and 34.1 lbmol of CO₂ is directed asstream 85 back through the series of three heat exchangers to re-heatthe CO₂ circulating fluid stream prior to entry into the combustor 220.

The pressurized CO₂ circulating fluid stream 85 is passed through thethird heat exchanger 450 to form stream 71 at a temperature of 114° C.and a pressure of 30.5 MPa. Stream 71 is passed through splitter 460such that 27.3 lbmol of CO₂ is directed as stream 71 b to the secondheat exchanger 440, and 6.8 lbmol of CO₂ is directed in stream 72 athrough a side heater 470. Stream 71 b and stream 72 a each have atemperature of 114° C. at a pressure of 30.5 MPa. The side heater 470uses heat (Q) from the air separator unit 30 to provide additional heatto the CO₂ circulating fluid stream. Passage of stream 71 b through thesecond heat exchanger 440 produces stream 73 at a temperature of 224° C.and a pressure of 30.5 MPa. Passage of stream 72 a through the sideheater 470 forms stream 72 b which likewise is at a temperature of 224°C. and a pressure of 30.4 MPa. Streams 73 and 72 b are combined in themixer 480 to form stream 74 at a temperature of 224° C. and a pressureof 30.3 MPa. Stream 74 is then passed through the first heat exchanger430 to provide the recycled CO₂ circulating fluid stream 236 at atemperature of 860° C. and a pressure of 30.0 MPa for inlet back intothe combustor 220.

Efficiency for the foregoing, modeled cycle was calculated based on theenergy generated in comparison to the LHV of the methane fuel and theadditional energy input into the system, as described above. Under themodeled conditions, an efficiency of approximately 53.9% was achieved.This is particularly surprising in that such an excellent efficiency canbe achieved while simultaneously preventing atmospheric discharge of anyCO₂ (particularly any CO₂ arising from combustion of the carboncontaining fuel).

Example 2 System and Method for Power Production with a Pulverized CoalPower Station Retrofit to Use a Recycled CO₂ Circulating Fluid

Another specific example of a system and method according to the presentinvention is illustrated in FIG. 12. The following description describesthe system in relation to a specific cycle under specific conditionsusing mathematical modeling.

In this model, the ability to retrofit a system and method as describedherein to a conventional pulverized coal fired power station isillustrated.

An O₂ stream 1056 at a pressure 30.5 MPa is introduced into atranspiration cooled combustor 220 along with a carbon containing fuel1055 (e.g., coal-derived gas produced by partial oxidation) at apressure of 30.5 MPa and a CO₂ circulating fluid stream 1053 at apressure of 30.5 MPa. The O₂ may be received from an air separator orsimilar device that can produce heat (Q), which can be drawn off for usein the system, such as to produce steam for expansion or to add heat toa cooled CO₂ circulating fluid stream. Combustion of the fuel in thecombustor 220 produces a combustion product stream 1054 at a temperatureof 1,150° C. and a pressure of 30.0 MPa. This stream is expanded acrossa turbine 320 (which may generally be referred to as a primary powerproduction turbine) to produce power by driving an electric generator1209. The expansion turbine discharge stream 1001 at a temperature of775° C. and a pressure of about 3.0 MPa is introduced into the hot endof a heat exchanger 1100 where the heat from the turbine dischargestream 1001 is used to superheat the high pressure steam flow 1031 andthe intermediate pressure steam flow 1032 produced in a conventionalpulverized coal fired power station 1800. Boiler feed water 1810 andcoal 1810 are input to the power station 1800 to produce the steam flows1031 and 1032 by combustion of the coal 1810. The transfer of heat inthe heat exchanger superheats the steam flows 1031 and 1032 from atemperature of about 550° C. to a temperature of about 750° C. to formthe steam flows 1033 and 1034, which are returned to the power stationas described below. This method achieves very high steam temperatureswithout the need for expensive high temperature alloys to be used in thelarge steam boilers of a conventional power station burning coal at nearatmospheric pressure. The steam flows 1033 and 1034 are expanded in athree stage turbine 1200 (which may generally be referred to as asecondary power production turbine) driving an electric generator 1210.The steam 1035 exiting the turbine 1200 is condensed in a condenser1220. Treated condensate 1036 is pumped to high pressure in with a feedwater pump 1230 and then is vaporized and superheated in the coal firedboiler 1800 for discharge into the heat exchanger 1100, as describedabove. This system is used to increase the power output and efficiencyof an existing coal fired power station.

The heat exchanger 100 is a Heatric type diffusion bonded plate heatexchanger with chemically milled passages typically constructed with ahigh temperature, high nickel content alloy, such as 617 alloy, which iscapable of handling high pressures and temperatures allowing significantsteam superheat and operation under oxidizing conditions. This heatexchanger is a high efficiency heat transfer unit with high heattransfer coefficients for all fluids.

The remaining portion of the system and method illustrated in FIG. 12 issimilar in structure and operation to the systems and methods otherwisedescribed herein. Specifically, the expansion turbine discharge stream1001 is cooled in the heat exchanger 1100 and leaves the cool end of theheat exchanger 1100 as discharge stream 1037, which is at a temperatureof 575° C. This stream 1037 is then passed through a second heatexchanger 1300 where it is cooled to a temperature of 90° C. and apressure of 2.9 MPa to from stream 1038. This stream is further cooledagainst a portion of the condensate 1057 from the power stationcondenser 1230 in a third heat exchanger 1310 to a temperature of 40° C.to form stream 1039, which is further cooled to a temperature of 27° C.against cooling water in a cold water heat exchanger 1320 to form stream1040 at a pressure of 2.87 MPa. The heat exchanger 1300 can be a Heatric310 stainless steel diffusion bonded unit.

The cooled stream 1040 at 30° C. is fed into the base of a packed column1330, which is equipped with a circulation pump 1340 that provides acounter-current weak acid circulation stream giving counter-currentcontacting between the incoming gas and the scrubbing weak acid. TheSO₂, SO₃, NO, and NO₂ are converted to HNO₃ and H₂SO₄ and absorbed inthe liquid together with condensed water and any other water solublecomponents. The net liquid product from the column 1330 is removed inline 1042, and the pressure is reduced to atmospheric pressure andenters a separator 1360. Dissolved CO₂ flashes off in line 1043, iscompressed using a pump 1350 to a pressure of 2.85 MPa, and flows asstream 1044 to join with stream 1045 leaving the top of column 1330.These combined streams form the CO₂ circulating fluid that will berecycled back into the combustor. Dilute H₂SO₄ and HNO₃ in water leavesas stream 1046 from the base of the separator 1360. The concentrationsdepend on the fuel composition and the temperature in the contactorcolumn 1330. Note that nitric acid preferably is present in the acidstream 1046, as nitric acid will react with any mercury present andremove this impurity completely.

The recycled CO₂ circulating fluid stream entering the compressor 1380is first dried to a dew point of about −60° C. in a desiccant dryer andthen purified to remove O₂, N₂, and Ar using a low temperatureseparation scheme, such as shown in European patent applicationEP1952874 A1, which is incorporated herein by reference.

The compressed, recycled CO₂ circulating fluid stream 1047 leavingcompressor 1380 at a pressure of 8.5 MPa is cooled against cooling waterat 27° C. in a cold water heat exchanger 1370 forming dense,supercritical CO₂ fluid stream 1048, which is pumped to a pressure of30.5 MPa and a temperature of 74° C. in the pump 1390 to form the highpressure, recycled CO₂ circulating fluid stream 1050. A portion of theCO₂ is removed from the stream 1050 as a CO₂ product stream 1049 to besequestered or otherwise disposed of without discharge to theatmosphere. In this embodiment, the CO₂ product stream 1049 is reducedin pressure to the required pipeline pressure of about 20 MPa and passedinto a CO₂ pipeline.

The remaining portion of the high pressure, recycled CO₂ circulatingfluid stream (now stream 1051) enters the cold end of the heat exchanger1300. This stream, which is a dense supercritical fluid at 74° C., mustreceive a considerable amount of low grade heat to convert it to a fluidwith a much lower specific heat at a temperature of 237° C. In thisembodiment, such low grade heat is provided by an LP steam stream 1052at a pressure of 0.65 MPa taken from the steam stream entering the lowpressure steam turbine of the conventional power station together withadiabatic heat of compression derived from the air compressors in thecryogenic oxygen plant supplying the O₂ stream 1056. The low pressuresteam exits the heat exchanger 1300 as stream 1301. Optionally, all ofthe heat can be provided by using a number of available steam streamsfrom the coal fired power station at pressures up to 3.8 MPa. Thisenergy also could be provided from the heat (Q) formed by the airseparation unit, as described above. The side stream heating of part ofthe recycle CO₂ stream provides a large part of the heat required at thecold end of the heat exchanger 1300 and allows a small temperaturedifference of only about 25° C. at the hot end of the heat exchanger1300, which increases overall efficiency.

The high pressure, high temperature, recycled CO₂ circulating fluidstream 1053 leaves the heat exchanger 1300 at a temperature of 550° C.and enters the combustor 220, where it is used to cool the combustiongases derived from combustion of a natural gas stream 1055 (in thisembodiment) with the 97% molar oxygen stream 1056 to produce thecombustion product stream 1054, as described above. In this embodiment,the turbine hot path and the first rows of turbine blades are cooledusing a CO₂ stream 1058 taken from the pump discharge stream 1050 at atemperature of 74° C.

If the system described above is operated as a stand alone power stationwith natural gas fuel simulated by pure CH₄, then the recycle CO₂ stream1053 enters the combustor at a temperature of about 750° C. and theturbine exhaust 1001 enters the heat exchanger 1300 at a temperature ofabout 775° C.

The efficiency of the stand alone power system in this embodiment is53.9% (LHV). This figure includes the power consumption for thecryogenic O₂ plant and the natural gas feed and CO₂ compressors. If thefuel was a simulated coal with a heating value of 27.92 Mj/kg (e.g.,partially oxidized with ash removed in a first combustor and filtrationunit followed by the combustion of the fuel gas and CO₂ mixture in asecond combustor), then the efficiency would be 54% (LHV). In both casesvirtually 100% of the CO₂ derived from carbon in the fuel would beproduced at 20 MPa pipeline pressure.

The system and method described above and illustrated in FIG. 12 withcoal fuel can be characterized as being applied to a power station withspecific parameters described below. The effect of converting apulverized coal fired power station according to the present inventionis calculated as follows:

Steam conditions HP steam: 16.6 MPa, 565° C., flow: 473 14 kg/sec

-   -   LP steam: 4.02 MPa, 565° C., flow: 371.62 kg/sec    -   Net power output: 493.7. Mw    -   Coal for existing station: 1256.1 Mw    -   Efficiency (LHV) net: 39.31%    -   CO₂ capture %: 0        Converted plant with existing station upgrade incorporating a        presently disclosed system and method:    -   CO₂ power system net power output: 371.7 Mw    -   Existing station net power: 639.1 Mw    -   Total net power: 1010.8 Mw    -   Coal for CO₂ power system: 1053.6 Mw    -   Coal for existing station: 1256.1 Mw    -   Overall efficiency (LHV) net: 43.76%    -   CO₂ capture %: 45.6%*

*Note that no CO₂ is captured from the existing station in this example.

Many modifications and other embodiments of the invention will come tomind to one skilled in the art to which this invention pertains havingthe benefit of the teachings presented in the foregoing descriptions andassociated drawings. Therefore, it is to be understood that theinvention is not to be limited to the specific embodiments disclosed andthat modifications and other embodiments are intended to be includedwithin the scope of the appended claims. Although specific terms areemployed herein, they are used in a generic and descriptive sense onlyand not for purposes of limitation.

1-88. (canceled)
 89. A power generation system comprising: atranspiration cooled combustor configured for receiving a fuel, O₂, anda CO₂ circulating fluid stream, and having at least one combustion stagethat combusts the fuel in the presence of the CO₂ circulating fluid andprovides a combustion product stream comprising CO₂ at a pressure of atleast about 8 MPa and a temperature of at least about 800° C.; a primarypower production turbine in fluid communication with the combustor, theprimary turbine having an inlet for receiving the combustion productstream and an outlet for release of a turbine discharge streamcomprising CO₂, the primary turbine being adapted to control pressuredrop such that the ratio of the pressure of the combustion productstream at the inlet compared to the turbine discharge stream at theoutlet is less than about 12; a primary heat exchange unit in fluidcommunication with the primary turbine for receiving the turbinedischarge stream and transferring heat therefrom to the CO₂ circulatingfluid stream; and at least one compressor in fluid communication withthe at least one heat exchanger for pressurizing the CO₂ circulatingfluid stream.
 90. The power generation system of claim 89, furthercomprising one or more separation devices positioned between the heatexchange unit and the at least one compressor for removal of one or moresecondary components present in the CO₂ circulating fluid in addition tothe CO₂.
 91. The power generation system of claim 89, comprising a firstcompressor adapted to compress the CO₂ circulating fluid stream to apressure that is above the CO₂ critical pressure.
 92. The powergeneration system of claim 91, comprising a cooling device adapted tocool the CO₂ circulating fluid stream exiting the first compressor to atemperature where its density is greater than about 200 kg/m³.
 93. Thepower generation system of claim 92, comprising a second compressoradapted to compress the cooled CO₂ circulating fluid stream to apressure required for input to the combustor.
 94. The power generationsystem of claim 92, further comprising one or more heat transfercomponents that transfers heat from an external source to the CO₂circulating fluid upstream from the combustor and downstream from thesecond compressor.
 95. The power generation system of claim 94, whereinthe heat transfer components are associated with an O₂ productiondevice.
 96. The power generation system of claim 89, further comprisinga second combustor located upstream from and in fluid communication withthe transpiration cooled combustor.
 97. The power generation system ofclaim 96, further comprising one or more filters or separation deviceslocated between the second combustor and the transpiration cooledcombustor.
 98. The power generation system of claim 97, wherein thesecond combustor is a transpiration cooled combustor.
 99. The powergeneration system of claim 96, further comprising a mixing device forforming a slurry of a particulate fuel material with a fluidizingmedium.
 100. The power generation system of claim 96, further comprisinga milling device for particularizing a solid fuel.
 101. The powergeneration system of claim 89, wherein the heat exchange unit comprisesat least two heat exchangers.
 102. The power generation system of claim101, wherein the heat exchange unit comprises a series of at least threeheat exchangers.
 103. The power generation system of claim 101, whereinthe first heat exchanger in the series is adapted for receiving theprimary turbine discharge stream and is formed of a high temperaturealloy that withstands a temperature of at least about 700° C.
 104. Thepower generation system of claim 89, wherein the primary powerproduction turbine comprises a series of at least two turbines.
 105. Thepower generation system of claim 89, further comprising a secondary heatexchange unit located between and in fluid communication with theprimary power production turbine and the primary heat exchange unit.106. The power generation system of claim 105, further comprising aboiler in fluid communication with the secondary heat exchange unit viaat least one steam stream.
 107. The power generation system of claim106, further comprising a secondary power production turbine having aninlet for receiving the at least one steam stream from the secondaryheat exchange unit.